1

May 13, 2016

OPG REPORTS ON NEW GENERATION PLANS

IN FIRST QUARTER FINANCIAL RESULTS Solar Energy to Complement Existing Clean Renewable Generation Fleet

  [Toronto] – Ontario Power Generation Inc. (OPG or Company) today reported that earnings from its electricity generation business segments were $320 million for the first quarter of 2016. The decrease in earnings of $17 million compared to the first quarter of 2015 was mainly due to increased planned outage expenditures at the nuclear generating stations during the first quarter of 2016. Total generation of 21.0 terawatt hours for the three months ended March 31, 2016 was comparable to the same quarter in 2015.

The latest quarter saw OPG win a competitive process to embark on a solar energy project. The project at OPG’s Nanticoke generating station (GS) site and adjacent lands is expected to have a capacity of 44 megawatts (MW). During the quarter, the Company also continued construction on the Peter Sutherland Sr. 28 MW hydroelectric station on the New Post Creek in northeastern Ontario.

"Both of these endeavours feature partnerships with local First Nations," said Jeff Lyash, President and CEO. "This makes for a total of four such partnerships for OPG, all of them to build clean generation that is free of GHG emissions. The projects also provide commercial and social benefits to the participating First Nations.”

Mr. Lyash added, "During the quarter, a major step was taken toward refurbishment of the four units at the Darlington Nuclear Station when we moved from the planning stage to the execution stage. The first reactor to be refurbished will be taken off line in the fourth quarter.”

Generating and Operating Performance

Electricity generated during the three months ended March 31, 2016 was 21.0 terawatt hours (TWh), compared to 21.3 TWh for the same quarter in 2015. The marginal decrease was mainly due to lower hydroelectric generation, resulting from lower electricity demand which increased the requirement to spill water.

 

 

2

With respect to electricity generated, Mr. Lyash said, “The excellent performance at the Darlington station reinforces our conviction that we’ll be able to operate it safely and efficiently for at least 30 more years after refurbishment. The capability factor at Darlington was 97.2 per cent in the first quarter, compared to 97.8 per cent for the same quarter in 2015.”

At the Pickering Nuclear Station, the capability factor was 72.8 per cent compared to 72.9 per cent in the first quarter of 2015. The decreases in the capability factor at the Darlington and Pickering stations were mainly due to a slight increase in the number of planned outage days. The availability of OPG’s hydroelectric generating stations remained at high levels, including availability of over 90 per cent at the regulated hydroelectric plants. For the contracted hydroelectric stations, availability decreased from 97.8 per cent in the first quarter of 2015 to 83.9 per cent in the first quarter of 2016, primarily due to a higher number of planned outage days at certain Lower Mattagami River stations.

Net income attributable to the Shareholder for the first quarter of 2016 was $123 million, compared to $234 million for the same quarter of 2015. The decrease in net income was mainly due to lower earnings from the Regulated – Nuclear Waste Management segment caused by lower earnings from the Decommissioning Segregated Fund.

For the electricity generation business segments, the slight decrease in income before interest and income taxes of $17 million compared to the first quarter of 2015 was mainly due to an increase in OM&A expenses, partly offset by a gain of $22 million stemming from the Ontario Energy Board’s January 2016 decision to reverse a portion of the Niagara Tunnel capital expenditures that had been disallowed in 2014. OPG also saw higher earnings from its contracted assets during the first quarter of 2016.

Generation Development

OPG is undertaking a number of generation development and life extension projects. Significant developments during the first quarter of 2016 were as follows:

Darlington Refurbishment

Life-to-date capital expenditures were $2,369 million as at March 31, 2016. The approved project budget for the four-unit refurbishment is $12.8 billion, including capitalized interest and escalation. The first unit refurbishment is scheduled to commence in the fourth quarter of 2016, with the last unit completed by 2026. Project work including construction of facilities, infrastructure upgrades and installation of safety enhancements is being completed in support of the execution phase of the project. Certain of these projects have been completed and the remaining projects are on-track to be completed in line with the execution schedule.

 

 

3

Peter Sutherland Sr. GS

Construction work on the new 28 MW hydroelectric generating station on the New Post Creek continued as scheduled during the first quarter of 2016. The project has a planned in-service date in the first half of 2018 and an approved budget of $300 million. Life-to-date capital expenditures were $125 million as at March 31, 2016.

Nanticoke Solar Facility

In March 2016, Nanticoke Solar LP, a partnership between OPG, SunEdison Canadian Construction LP and the Six Nations Development Corporation, was selected to develop a 44 MW solar facility at OPG’s Nanticoke GS site and adjacent lands in Haldimand County, Ontario. In March 2016, the partnership and the Independent Electricity System Operator executed a 20-year contract for the development and operation of the facility. This project is OPG’s fourth generation development partnership with First Nations. The Company is working with its partners to obtain the required approvals and permits to enable the start of construction planned for late-2017 or early-2018.

 

 

4

FINANCIAL AND OPERATIONAL HIGHLIGHTS Three Months Ended March 31(millions of dollars – except where noted) (unaudited) 2016 2015 Revenue 1,478 1,355 Fuel expense 172 157 Gross margin 1,306 1,198 Operations, maintenance and administration 686 665 Depreciation and amortization 312 196 Accretion on fixed asset removal and nuclear waste management liabilities 232 224 Earnings on nuclear funds - (a reduction to expenses) (147) (231) Income from investments subject to significant influence (8) (11) Other net expenses (11) 13 Income before interest and income taxes 242 342 Net interest expense 33 47 Income tax expense 81 56 Net income 128 239 Net income attributable to the Shareholder 123 234 Net income attributable to non-controlling interest 1 5 5

Income (loss) before interest and income taxes Electricity generation business segments 320 337 Regulated – Nuclear Waste Management (83) 9 Services, Trading, and Other Non-Generation 5 (4) Total income before interest and income taxes 242 342Cash flow Cash flow provided by operating activities 366 455Electricity generation (TWh) Regulated – Nuclear Generation 12.3 12.2 Regulated – Hydroelectric 7.9 8.2 Contracted Generation Portfolio 2 0.8 0.9 Total electricity generation 21.0 21.3Nuclear unit capability factor (per cent) Darlington GS 97.2 97.8 Pickering GS 72.8 72.9Availability (per cent) Regulated – Hydroelectric 94.8 91.5 Contracted Generation Portfolio – Hydroelectric 83.9 97.8Equivalent forced outage rate Contracted Generation Portfolio – Thermal 0.9 22.9

Return on Equity Excluding Accumulated Other Comprehensive Income (ROE Excluding AOCI) for the twelve months ended March 31, 2016 and December 31, 2015 (%) 3 2.9 4.0Funds from Operations (FFO) Adjusted Interest Coverage for the twelve months ended March 31, 2016 and December 31, 2015 (times) 3 5.2 5.0

1 Relates to the 25 per cent interest of a corporation wholly owned by the Moose Cree First Nation in the Lower Mattagami Limited Partnership.

2 Includes OPG’s share of generation volume from its 50 per cent ownership interests in the Portlands Energy Centre and Brighton Beach GS.

3 ROE Excluding AOCI and FFO Adjusted Interest Coverage are non-GAAP financial measures and do not have any standardized meaning prescribed by US GAAP. Additional information about these measures is provided in OPG's Management’s Discussion and Analysis for the three months ended March 31, 2016, under the section Supplementary Non-GAAP Financial Measures.

 

 

 

5

Ontario Power Generation Inc. is an Ontario-based electricity generation company whose principal business is the generation and sale of electricity in Ontario. Our focus is on the efficient production and sale of electricity from our generation assets, while operating in a safe, open, environmentally responsible, and commercially sound manner. Ontario Power Generation Inc.’s unaudited interim consolidated financial statements and Management’s Discussion and Analysis as at and for the three months ended March 31, 2016, can be accessed on OPG’s web site (www.opg.com), the Canadian Securities Administrators’ web site (www.sedar.com), or can be requested from the Company.

For further information, please contact: Investor Relations 416-592-6700 1-866-592-6700

Investor.relations@opg.com

Media Relations 416-592-4008 1-877-592-4008

ONTARIO POWER GENERATION INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

2016 FIRST QUARTER REPORT

TABLE OF CONTENTS Forward-Looking Statements 2

The Company 3

Highlights 4

Core Business, Strategy and Outlook 8

Discussion of Operating Results by Business Segment 13

Regulated – Nuclear Generation Segment 13

Regulated – Nuclear Waste Management Segment 14

Regulated – Hydroelectric Segment 15

Contracted Generation Portfolio Segment 16

Services, Trading, and Other Non-Generation Segment 17

Liquidity and Capital Resources 17

Balance Sheet Highlights 19

Changes in Accounting Policies and Estimates 19

Risk Management 20

Related Party Transactions 21

Internal Controls over Financial Reporting and Disclosure Controls 22

Quarterly Financial Highlights 23

Supplementary Non-GAAP Financial Measures 24

 

 

2

ONTARIO POWER GENERATION INC. MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) should be read in conjunction with the unaudited interim

consolidated financial statements and accompanying notes of Ontario Power Generation Inc. (OPG or Company) as

at and for the three months ended March 31, 2016. OPG’s unaudited interim consolidated financial statements are

prepared in accordance with United States generally accepted accounting principles (US GAAP) and are presented in

Canadian dollars.

For a complete description of OPG’s corporate strategies, risk management, corporate governance, and the effect of

critical accounting policies and estimates on OPG’s results of operations and financial condition, this MD&A should

also be read in conjunction with OPG’s audited consolidated financial statements, accompanying notes, and the

MD&A as at and for the year ended December 31, 2015.

As required by Ontario Regulation 395/11, as amended, a regulation under the Financial Administration Act (Ontario),

OPG adopted US GAAP for the presentation of its consolidated financial statements, effective January 1, 2012. In

2014, the Ontario Securities Commission approved an exemption which allows OPG to apply US GAAP up to

January 1, 2019. The term of the exemption is subject to certain conditions, which may result in the expiry of the

exemption prior to January 1, 2019. For details, refer to the heading, Exemptive Relief for Reporting under US

GAAP, in the section, Critical Accounting Policies and Estimates, in OPG’s 2015 annual MD&A. This MD&A is dated

May 13, 2016.

FORWARD-LOOKING STATEMENTS

The MD&A contains forward-looking statements that reflect OPG’s current views regarding certain future events and

circumstances. Any statement contained in this document that is not current or historical is a forward-looking statement.

OPG generally uses words such as “anticipate”, “believe”, “foresee”, “forecast”, “estimate”, “expect”, “schedule”, “intend”,

“plan”, “project”, “seek”, “target”, “goal”, “strategy”, “may”, “will”, “should”, “could” and other similar words and expressions

to indicate forward-looking statements. The absence of any such word or expression does not indicate that a statement is

not forward-looking.

All forward-looking statements involve inherent assumptions, risks and uncertainties, including those set out under

the section, Risk Management, and forecasts discussed under the heading, Outlook. All forward-looking statements

could be inaccurate to a material degree. In particular, forward-looking statements may contain assumptions such as

those relating to OPG’s fuel costs, generating station performance and availability, cost of fixed asset removal and

nuclear waste management, performance of investment funds, conversion of generating stations to alternative fuels,

refurbishment of existing facilities, development and construction of new facilities, pension and other post-

employment benefit (OPEB) obligations and funds, income taxes, proposed new legislation, the ongoing evolution of

the Ontario electricity industry, environmental and other regulatory requirements, health, safety and environmental

developments, business continuity events, the weather, applications to the Ontario Energy Board (OEB) for regulated

prices, the impact of regulatory decisions by the OEB, forecasts of earnings, cash flows, Funds from Operations

(FFO) Adjusted Interest Coverage, Return on Common Equity Excluding Accumulated Other Comprehensive Income

(ROE Excluding AOCI), and capital expenditures. Accordingly, undue reliance should not be placed on any forward-

looking statement. The forward-looking statements included in this MD&A are made only as of the date of this

MD&A. Except as required by applicable securities laws, OPG does not undertake to publicly update these forward-

looking statements to reflect new information, future events or otherwise.

3

THE COMPANY

OPG is an Ontario-based electricity generation company whose principal business is the generation and sale of

electricity in Ontario. OPG was established under the Business Corporations Act (Ontario) and is wholly owned by

the Province of Ontario (Province or Shareholder).

As at March 31, 2016, OPG’s electricity generation portfolio had an in-service capacity of 17,052 megawatts (MW).

OPG operates two nuclear generating stations, three thermal generating stations, 65 hydroelectric generating

stations, and one wind power turbine. In addition, OPG and TransCanada Energy Ltd. co-own the 550 MW Portlands

Energy Centre (PEC) gas-fired combined cycle generating station (GS). OPG and ATCO Power Canada Ltd. co-own

the 560 MW Brighton Beach gas-fired combined cycle GS (Brighton Beach). OPG’s 50 percent share of the in-

service capacity and generation volume of these co-owned facilities is included in the generation portfolio statistics

set out in this report. The income from the co-owned facilities is accounted for using the equity method of accounting,

and OPG’s share of income is presented as income from investments subject to significant influence in the

Contracted Generation Portfolio segment.

OPG also owns two other nuclear generating stations, the Bruce A GS and the Bruce B GS, which are leased on a

long-term basis to Bruce Power LP (Bruce Power). Income from these leased stations is included in revenue under

the Regulated – Nuclear Generation segment. The leased stations are not included in the generation portfolio

statistics set out in this report. A description of OPG’s segments is provided in OPG’s 2015 annual MD&A in the

section, Business Segments.

OPG does not operate PEC, Brighton Beach, the Bruce A GS, and the Bruce B GS.

The in-service generating capacity by business segment as at March 31, 2016 and December 31, 2015 was as follows:

  As at

March 31 December 31

(MW) 2016 2015 Regulated – Nuclear Generation 6,606 6,606 Regulated – Hydroelectric 6,425 6,428 Contracted Generation Portfolio 1 4,021 4,021 Total 17,052 17,055 1 Includes OPG’s share of in-service generating capacity of 275 MW for PEC and 280 MW for Brighton Beach.

4

HIGHLIGHTS

Overview of Results

This section provides an overview of OPG’s unaudited interim consolidated operating results. Significant factors

which contributed to OPG’s results during the three months ended March 31, 2016, compared to the same period in

2015, are discussed below.

Three Months Ended March 31 (millions of dollars – except where noted) (unaudited) 2016 2015 Revenue 1,478 1,355 Fuel expense 172 157 Gross margin 1,306 1,198 Operations, maintenance and administration 686 665 Depreciation and amortization 312 196 Accretion on fixed asset removal and nuclear waste management liabilities 232 224Earnings on nuclear fixed asset removal and nuclear waste management funds (147) (231) Income from investments subject to significant influence (8) (11) Property taxes 12 13 1,087 856 Income before other gains, interest, and income taxes 219 342 Other gains (23) - Income before interest and income taxes 242 342 Net interest expense 33 47 Income before income taxes 209 295 Income tax expense 81 56 Net income 128 239 Net income attributable to the Shareholder 123 234 Net income attributable to non-controlling interest 1 5 5 Electricity production (TWh) 2 21.0 21.3 Cash flow provided by operating activities 366 455 1 Relates to the 25 percent interest of the Amisk-oo-Skow Finance Corporation, a corporation wholly owned by the Moose Cree

First Nation, in the Lower Mattagami Limited Partnership. 2 Includes OPG’s share of generation volume from its 50 percent ownership interests in PEC and Brighton Beach.

Net income attributable to the Shareholder decreased by $111 million during the first quarter of 2016, compared to

the same quarter in 2015.

Income before interest and income taxes decreased by $100 million, compared to the first quarter of 2015. The

following summarizes the significant items which contributed to the variance:

Significant factors that reduced income before interest and income taxes:

Decrease in earnings on the nuclear fixed asset removal and nuclear waste management funds (Nuclear

Funds) of $84 million, primarily due to lower earnings on the Decommissioning Segregated Fund

(Decommissioning Fund)

Higher operations, maintenance and administration (OM&A) expenses of $37 million for the Regulated –

Nuclear Generation segment, primarily as a result of an increase in planned outage activities during the first

quarter of 2016, compared to the same quarter in 2015.

5

Significant factors that increased income before interest and income taxes:

A gain of $22 million recorded during the first quarter of 2016 reflecting the OEB’s January 2016 decision to

reverse a portion of an earlier capital cost disallowance related to Niagara Tunnel project expenditures, in

response to OPG’s motion requesting the OEB to review and vary parts of its November 2014 decision

Lower earnings of $16 million during the first quarter of 2015 in the Contracted Generation Portfolio

segment, primarily as a result of a provision made in that quarter related to an Independent Electricity

System Operator (IESO) audit.

Net interest expense decreased by $14 million during the first quarter of 2016, compared to the same quarter in 2015,

primarily due to higher interest capitalized for the Darlington Refurbishment project expenditures.

Income tax expense for the three months ended March 31, 2016 was $81 million compared to $56 million for the

same period in 2015. The increase in income tax expense was primarily due to a decrease in regulatory asset

balances related to income taxes recorded in the first quarter of 2016.

Segment Results

The following table summarizes OPG’s income before interest and income taxes by business segment. A detailed

discussion of OPG’s performance by reportable segment is included in the section, Discussion of Operating Results

by Business Segment.

Three Months Ended March 31 (millions of dollars) 2016 2015

Income (loss) before interest and income taxes Regulated – Nuclear Generation 46 88 Regulated – Hydroelectric 196 187 Contracted Generation Portfolio 78 62 Total electricity generation business segments 320 337 Regulated – Nuclear Waste Management (83) 9 Services, Trading, and Other Non-Generation 5 (4) 242 342

Electricity Generation

Electricity generation was as follows:

Three Months Ended March 31 (TWh) 2016 2015 Regulated – Nuclear Generation 12.3 12.2 Regulated – Hydroelectric 7.9 8.2 Contracted Generation Portfolio 1 0.8 0.9 Total OPG electricity generation 21.0 21.3 Total electricity generation by all other generators in Ontario 2 18.9 21.5 1 Includes OPG’s share of generation volume from its 50 percent ownership interests in PEC and Brighton Beach. 2 Non-OPG generation is calculated as the Ontario electricity demand plus net exports, as published by the IESO, minus total OPG

electricity generation.

6

The decrease in OPG’s electricity generation during the first quarter of 2016, compared to the first quarter of 2015,

was primarily due to lower generation of 0.3 terawatt hours (TWh) from the Regulated – Hydroelectric segment. The

decrease in Regulated – Hydroelectric generation was primarily due to a higher volume of water spilled as a result of

surplus baseload generation (SBG) conditions from lower Ontario electricity demand, partially offset by the effect of

higher water flows.

OPG’s operating results are affected by changes in grid-supplied electricity demand resulting from variations in

seasonal weather conditions, changes in economic conditions, the impact of small scale generation embedded in

distribution networks, and the impact of conservation efforts in the province. Ontario’s electricity demand as reported

by the IESO was 35.2 TWh during the first quarter of 2016, compared to 37.5 TWh during the same quarter of 2015.

Baseload generation supply surplus to Ontario demand was more prevalent during the first quarter of 2016 than in

the first quarter of 2015 due to warmer winter conditions and higher water flows in the province in 2016. The surplus

to the Ontario market is managed by the IESO, mainly through generation reductions at hydroelectric and nuclear

stations and grid-connected renewable resources. Reducing hydroelectric production, which often results in spilling

of water, is the first measure that the IESO uses to manage SBG conditions. During the first quarter of 2016, OPG

lost 1.7 TWh of hydroelectric generation due to SBG conditions, compared to 0.3 TWh during the same period in

2015. The gross margin impact of production forgone at OPG’s regulated hydroelectric stations due to SBG

conditions was offset by a regulatory variance account authorized by the OEB.

Average Sales Prices

The majority of OPG’s generation is from the Regulated – Nuclear Generation and Regulated – Hydroelectric

segments. The regulated prices authorized by the OEB for electricity generated from OPG’s nuclear and regulated

hydroelectric generating stations are discussed in OPG’s 2015 annual MD&A in the section, Revenue Mechanisms

for Regulated and Unregulated Generation.

The average sales price for the Regulated – Nuclear Generation segment was 7.0 cents per kilowatt hour (¢/kWh)

during the first quarter of 2016, compared to 6.0 ¢/kWh during the same quarter in 2015. The increase was due to a

higher rate rider in effect during the first quarter of 2016 for OPG’s nuclear generation related to the recovery of

variance and deferral account balances previously approved by the OEB. The average sales price for the Regulated

– Hydroelectric segment was 4.4 ¢/kWh during the first quarter of 2016, compared to 4.5 ¢/kWh during the same

quarter in 2015. The marginal decrease was primarily due to lower rate riders in effect during the first quarter of 2016

for OPG’s regulated hydroelectric generation related to the recovery of variance and deferral account balances. The

revenue impact of rate riders is largely offset by changes in amortization expense related to regulatory balances.

Cash Flow from Operations

Cash flow provided by operating activities for the three months ended March 31, 2016 was $366 million, compared to

$455 million for the three months ended March 31, 2015. This decrease was primarily due to higher OM&A

expenditures in the first quarter of 2016 and the payment of a supplemental rent rebate to Bruce Power pursuant to a

provision under the lease agreement for the Bruce nuclear generating stations between Bruce Power and OPG

(Bruce Lease). This provision was eliminated effective December 4, 2015 as part of the 2015 amendments to the

lease agreement, as discussed in OPG’s 2015 annual MD&A in the section, Recent Developments, under the

heading, Highlights. The decrease in cash flow provided by operating activities for the first quarter of 2016 was

partially offset by an increase in generation revenue receipts from higher nuclear rate riders.

ROE Excluding AOCI

ROE Excluding AOCI is an indicator of OPG’s performance consistent with the Company’s strategy to provide value

to the Shareholder. ROE Excluding AOCI is measured over a 12-month period.

7

ROE Excluding AOCI was 2.9 percent for the 12 months ended March 31, 2016 and 4.0 percent for the 12 months

ended December 31, 2015. ROE Excluding AOCI decreased for the period primarily due to lower net income

attributable to the Shareholder.

FFO Adjusted Interest Coverage

FFO Adjusted Interest Coverage is an indicator of OPG’s ability to meet interest obligations from operating cash

flows. The indicator is measured over a 12-month period. FFO Adjusted Interest Coverage for the 12 months ended

March 31, 2016 was 5.2 times, compared to 5.0 times for the 12 months ended December 31, 2015. FFO Adjusted

Interest Coverage increased in 2016 primarily due to higher generation revenue as a result of higher nuclear rate

riders in effect during the 12 months ended March 31, 2016, compared to the 12 months ended December 31, 2015.

Nuclear Total Generating Cost per Megawatt Hour

Nuclear Total Generating Cost (TGC) per Megawatt Hour (MWh) is used to measure the cost performance of OPG’s

nuclear generating assets. Nuclear TGC per MWh is defined as OM&A expenses of the Regulated – Nuclear

Generation segment (excluding Darlington Refurbishment project costs, the impact of regulatory variance and

deferral accounts, and expenses ancillary to OPG’s nuclear electricity generation business), nuclear fuel expense for

OPG-operated stations (excluding the impact of regulatory variance and deferral accounts), and capital expenditures

of the Regulated – Nuclear Generation segment (excluding Darlington Refurbishment project costs) incurred during

the period, divided by nuclear electricity generation. In 2015, the Nuclear TGC per MWh indicator was amended with

a view to enhance comparability across periods including adjustments to remove the impact of regulatory variance

and deferral accounts. The change is reflected in the comparative period presented in this MD&A. The Nuclear TGC

per MWh is discussed further in the section, Discussion of Operating Results by Business Segment.

ROE Excluding AOCI, FFO Adjusted Interest Coverage, and Nuclear TGC are not measurements in accordance with

US GAAP and should not be considered alternative measures to net income, cash flows from operating activities, or

any other performance measure under US GAAP. OPG believes that these non-GAAP financial measures are

effective indicators of its performance and are consistent with the Company’s strategic imperatives and related

objectives. The definition and calculation of ROE Excluding AOCI, FFO Adjusted Interest Coverage, and Nuclear

TGC are found in the section, Supplementary Non-GAAP Financial Measures.

Recent Developments

Contract Award for Nanticoke Solar Facility

In March 2016, Nanticoke Solar LP, a partnership between OPG, SunEdison Canadian Construction LP, a solar

project developer, and Six Nations Development Corporation, was selected, through the IESO’s Large Renewable

Procurement (LRP) program, to develop a 44 MW solar facility at OPG’s Nanticoke GS site and adjacent lands in

Haldimand County, Ontario. The LRP program is a competitive bidding process for procuring large renewable energy

projects in Ontario.

In March 2016, Nanticoke Solar LP and the IESO executed a 20-year LRP contract, which formalized the terms and

conditions for the development and operation of the new solar facility. Also in March 2016, the required performance

and completion security for the project was provided to the IESO. The Company is working with its partners to obtain

approvals and permits required to enable the commencement of construction planned for late-2017 or early-2018.

Acquisition of Hydro One Limited Shares

During 2015, OPG entered into renewed three-year collective bargaining agreements with the Power Workers’ Union

(PWU) and The Society of Energy Professionals (The Society). Changes to the respective collective agreements

included increases to employee pension plan contributions and provisions for existing employees represented by the

PWU and The Society with eligibility to annually receive common shares of Hydro One Limited (Hydro One) for up to

15 years starting in the third year of the respective agreements.

8

In April 2016, OPG acquired nine million common shares of Hydro One at $23.65 per share as part of a secondary

share offering by the Province through a syndicate of underwriters. OPG paid the same price as other investors in

the offering. The acquisition was made for investment purposes to mitigate the risk of future price volatility related to

OPG’s future share delivery obligations under the collective agreements. The shares acquired in this transaction

represent the substantial majority of OPG’s currently anticipated purchases of Hydro One shares.

Federal Court of Appeal Decision on the Environmental Assessment for the Darlington Refurbishment Project

In 2013, the Canadian Nuclear Safety Commission (CNSC) and Fisheries and Oceans Canada, as responsible

authorities, issued a decision on the environmental assessment (EA) for the Darlington Refurbishment project, which

confirmed that taking into account identified mitigation measures, the project was not likely to cause significant

adverse environmental effects. Later in 2013, the EA decision was challenged by certain intervenors in the EA

process by way of a request for a judicial review. The challenge was dismissed by the court in 2014, following which

the intervenors filed an appeal to the Federal Court of Appeal. In April 2016, the Federal Court of Appeal

unanimously dismissed the request for a judicial review. The Court determined that there were no gaps in the EA,

that there was nothing unreasonable about the discretionary determinations made by the responsible authorities, and

that the intervenors’ arguments were not borne out by the evidence. OPG was also awarded its costs of the appeal

as the successful party.

Supreme Court Decision on Leave to Appeal the EA for New Nuclear Units

In November 2015, an application for leave to appeal was filed with the Supreme Court of Canada (Supreme Court)

by the parties that brought the judicial review for the Darlington New Nuclear Project EA following the Joint Review

Panel’s (JRP) Report, which was approved by the federal government in May 2012. The JRP Report had concluded

that the project was not likely to cause significant adverse environmental effects, given mitigation. In April 2016, the

Supreme Court dismissed the application for leave to appeal, which concluded the litigation.

CORE BUSINESS, STRATEGY AND OUTLOOK

The discussion in this section is qualified in its entirety by the caution included in the section, Forward-Looking

Statements, at the beginning of the MD&A.

OPG delivers value to Ontario electricity customers and its Shareholder, the Province of Ontario, by reliably and cost

effectively producing electricity from its diversified portfolio of clean energy generating assets while operating in a

safe, transparent, environmentally responsible and commercial sound manner. OPG also seeks to pursue, on a

commercial basis, generation development projects and other business growth opportunities to the benefit of the

Shareholder.

The following sections provide an update to OPG’s disclosures in the 2015 annual MD&A related to its four key

strategic imperatives – operational excellence, project excellence, financial strength, and social licence. A detailed

discussion of these strategic imperatives is included in the 2015 annual MD&A under the headings, Operational

Excellence, Project Excellence, Financial Strength, and Social Licence in the Core Business and Strategy section.

Operational Excellence

Operational excellence at OPG is accomplished by the safe and environmentally responsible generation of reliable

and cost-effective electricity from the Company’s generating assets through a highly trained and engaged workforce.

Public Safety

To ensure continued public safety, radiation exposure to members of the public resulting from the operation of OPG’s

nuclear generating stations is estimated on an annual basis for those individuals who live or work near the stations.

9

The annual dose to the public resulting from operations of each nuclear facility is expressed in microsieverts (μSv),

which is an international unit of radiation dose measurement. For 2015, the annual public doses resulting from the

Darlington GS operations and the Pickering GS operations were 0.5 μSv and 1.2 μSv, respectively, which is

approximately 0.1 percent of the annual legal limit of 1,000 μSv.

Electricity Generation Production and Reliability

Work continued to progress to enhance the integration of life cycle management and refurbishment programs at

the Darlington GS during the first quarter of 2016. This included implementing staffing strategies to support both

ongoing station operations and the refurbishment project, planning and incorporating pre-requisite work for the

refurbishment into the station’s work schedule, and identifying life cycle and aging management work to sustain

safe and reliable station operations for the next three decades. Refer to the section, Project Excellence, for a

further discussion of the Darlington Refurbishment project.

Construction planning activities and contractor mobilization were completed for the execution of the Sir Adam

Beck Pump GS reservoir refurbishment during the first quarter of 2016. Construction and dewatering activities

commenced on April 1, 2016.

During the first quarter of 2016, major equipment overhauls and rehabilitation work were completed at Unit 5 of

the Sir Adam Beck Pump GS, and dam concrete replacement work commenced at the Kakabeka Falls GS.

OPG continues to develop the decommissioning plan for the Nanticoke GS, which will be designed to

accommodate the construction and operation of the new 44 MW solar facility discussed in the Highlights section.

The costs of decommissioning the Nanticoke GS are charged to a previously established decommissioning

provision.

Environmental Performance

In February 2016, the Climate Change Mitigation and Low-Carbon Economy Act (Bill 172) was introduced in the

Ontario legislature. Bill 172 provides a foundation for an Ontario cap-and-trade program to regulate greenhouse gas

(GHG) emissions in Ontario, effective January 1, 2017. With OPG's low GHG emitting fleet, the legislation and

regulations, as drafted, are not expected to have a material adverse financial impact on the Company. As proposed,

the cap-and-trade program may result in increased fuel costs for some of OPG-owned generating facilities and

OPG’s share of co-owned generating facilities. Based on the 2015 emissions data for these facilities, the increased

fuel costs to OPG, if the cap-and-trade program had been in place, would not have had a material impact on the

Company.

Disclosures relating to the Company’s environmental policies and environmental risks are provided in the 2015

annual MD&A.

Improving Efficiency and Reducing Costs

Since the beginning of 2011 to the end of the first quarter of 2016, through the Business Transformation and other

initiatives, OPG has reduced regular headcount from ongoing operations by over 2,800, achieving cumulative savings

of approximately $1 billion. OPG continues to identify and pursue opportunities aimed at further cost efficiencies and

productivity improvement across operating business units and support functions, while ensuring that adequate human

resources are in place to meet the Company’s business objectives. This includes embedding continuous

improvement into organizational values and expected behaviours.

10

Project Excellence

OPG is pursuing a number of generation development and other projects in support of Ontario’s electricity planning

initiatives. The status updates for OPG’s current major projects as at March 31, 2016 are outlined below.

Project Capital Approved Planned Status expenditures budget in-service (millions of dollars) Year-to-date Life-to-date date

Darlington Refurbishment

203 0 2,369 0 12,800 1 2026 1 On track to commence Unit 2 refurbishment in the fourth quarter of 2016. See update below.

Deep Geologic Repository for Low and Intermediate Level Waste

1 2 187 2

Additional information required by the Canadian Environmental Assessment Agency is being prepared. See update below.

Peter Sutherland Sr. GS

30 0 125 0 300 0 First half of 2018

The project is tracking on budget and on schedule.

1 The total project budget of $12.8 billion is for the refurbishment of the four units at the Darlington GS, with the last unit scheduled to be completed by 2026. The refurbishment of the first unit is scheduled to commence in the fourth quarter of 2016. OPG will be required to obtain the Province’s approval prior to proceeding with each of the remaining unit refurbishments.

2 Expenditures are funded by the nuclear fixed asset removal and nuclear waste management liabilities (Nuclear Liabilities).

Darlington Refurbishment

The Darlington generating units are approaching their originally designed end-of-life. Refurbishment of the four

generating units is expected to extend the operating life of the Darlington GS by approximately 30 years.

In 2016, the Darlington Refurbishment project transitioned from the planning phase to the execution phase, as OPG

began preparations for the refurbishment of the first unit, Unit 2, which is scheduled to start in the fourth quarter of

2016.

Preparation activities on the major sub-projects are progressing in line with the first unit’s refurbishment schedule.

Manufacturing of the tools that will be used to perform the removal and replacement of fuel channel assemblies and

feeder tubes in each reactor is complete. Delivery of these tools is in progress, tracking on plan for completion in the

second quarter of 2016. A modification to increase the efficiency of the de-fueling equipment was successfully

commissioned in January 2016, including an on-reactor demonstration. De-fueling is the first critical refurbishment

activity once the unit is removed from service.

Execution of pre-breaker open work to support the first unit’s refurbishment is in progress and is expected to be

completed prior to the commencement of refurbishment activities on the first unit. Project support activities and

activities in support of requirements set out in the CNSC-approved Integrated Implementation Plan for the Darlington

GS are also underway. Pre-requisite projects including construction of facilities, infrastructure upgrades and

installation of safety enhancements have either been completed or are tracking to be completed in line with the

refurbishment execution schedule.

Deep Geologic Repository for Low and Intermediate Level Waste

In February 2016, the federal Minister of Environment and Climate Change requested additional information on

certain aspects of the EA for OPG’s proposed Low and Intermediate Level Waste (L&ILW) Deep Geologic Repository

(DGR), including information related to alternate locations for the project and the impact on cumulative environmental

effects if the Nuclear Waste Management Organization’s future used fuel repository were located in close proximity to

11

the proposed L&ILW DGR. In April 2016, OPG informed the Canadian Environmental Assessment Agency that it

expects to submit the requested information by the end of 2016.

Peter Sutherland Sr. GS

The project to construct the Peter Sutherland Sr. hydroelectric generating station is tracking on budget and on

schedule. Construction work on the project continued during the first quarter of 2016, including construction of the

project camp and setup of the batch concrete plant, power house concreting, slope stabilization of the intake canal,

coffer dam rebuild, and headpond clearing activities. By the end of March 2016, construction and concrete work of

below grade components were completed.

Financial Strength

As a commercial enterprise, OPG’s financial priority is to achieve a consistent level of strong financial performance

that delivers an appropriate level of return on the Shareholder’s investment and positions the Company for future

growth.

Increase Revenue, Reduce Costs and Achieve Appropriate Return

In the second quarter of 2016, OPG plans to file a 5-year application with the OEB for new base regulated prices for

production from its regulated hydroelectric and nuclear facilities, with a proposed effective date of January 1, 2017.

The new prices are expected to be determined, for the first time since OPG’s prescribed assets became subject to

rate regulation by the OEB, on the basis of an incentive regulation ratemaking methodology for the regulated

hydroelectric operations and a custom incentive regulation basis for the nuclear operations. In addition, the

application is expected to seek new rate riders, effective January 1, 2017, to recover or refund the December 31,

2015 balances in most of OPG’s OEB-authorized variance and deferral accounts, less amounts previously approved

for recovery or refund through existing rate riders in effect to December 31, 2016.

Consistent with the November 2015 amendment to Ontario Regulation 53/05, OPG plans to incorporate a nuclear

rate smoothing proposal into the application, with a view of making more stable year-over-year changes in the

nuclear base regulated prices during the Darlington refurbishment period. Under rate smoothing, collection of a

portion of the approved revenue requirement will be deferred into the future. OPG expects to recognize the deferred

amounts as income in the period to which the approved revenue requirement relates. The planned application will

seek to ensure that nuclear regulated prices under the rate smoothing approach allows for sufficient cash flow to

meet the Company’s liquidity needs, support cost-effective funding for the Darlington Refurbishment project and other

expenditures, and maintain the Company’s investment grade credit rating, while taking into account both near-term

and future impacts on customers. Further details on the requirements of Ontario Regulation 53/05 with respect to

nuclear rate smoothing can be found in OPG’s 2015 MD&A under the heading, Amendments to Ontario Regulation

53/05, in the Highlights section.

Ensure Availability of Cost Effective Funding

In April 2016, DBRS Ltd. re-affirmed the long-term credit rating on OPG’s debt at A (low), and OPG’s commercial

paper rating at R-1 (low). All ratings from DBRS Ltd. have a stable outlook.

12

Outlook

The financial performance of OPG’s regulated operations is driven, in large part, by the outcome of applications for

regulated prices to the OEB. The existing base regulated prices were established by the OEB in late-2014 based on

a forecast of revenue requirement and production for the regulated facilities for the 2014 to 2015 period. The

outcome of the OEB rate application for new base regulated prices planned for the second quarter of 2016 is

expected to provide substantial price certainty for the regulated business for the 2017 to 2021 period. Further

discussion regarding OPG’s planned rate application to the OEB can be found under the heading, Financial Strength,

in the Core Business, Strategy and Outlook section.

In addition to receiving base regulated prices, during 2016, OPG is authorized to recover over $600 million in

previously approved variance and deferral account balances, through rate riders established by the OEB in October

2015. While the revenue impact of the riders will be largely offset by a corresponding increase in amortization

expense related to regulatory balances resulting in no significant net income impact, the recovery of the balances will

favourably impact operating cash flow and the FFO Adjusted Interest Coverage indicator for 2016. The existing rate

riders will expire on December 31, 2016.

Several OEB-authorized regulatory variance and deferral accounts currently in place contribute to reducing the

relative variability of the Company’s income and ROE Excluding AOCI. In particular, existing variance accounts

related to variability in regulated hydroelectric water flows and SBG conditions are expected to continue to result in

generally more stable earnings from the Regulated – Hydroelectric segment, compared to the Regulated – Nuclear

segment. There is currently no regulatory variance or deferral account related to the generation performance of the

OPG-operated nuclear stations. OPG continues to operate and maintain its nuclear facilities with a view to optimize

their performance and availability, while improving the overall reliability and predictability of the fleet. OPG’s planned

rate application will request the continuation of applicable variance and deferral accounts for the 2017 to 2021 period.

Electricity generated from most of OPG’s non-regulated assets is subject to Energy Supply Agreements with the

IESO. Based on these agreements, OPG expects the Contracted Generation Portfolio segment to generate a

generally stable level of earnings and cash flow going forward.

OPG’s forecast capital expenditures for 2016 are approximately $1.9 billion. This includes amounts for the

Darlington Refurbishment project, hydroelectric development projects including the construction of the Peter

Sutherland Sr. GS, and sustaining capital investments across the generating fleet.

In addition to the operating and financial performance of the electricity generation business, OPG’s results are

impacted by the earnings on the Nuclear Funds established pursuant to the Ontario Nuclear Funds Agreement

(ONFA) to fund expenditures associated with the long-term management of used nuclear fuel and L&ILW and the

decommissioning of OPG’s nuclear stations and waste management facilities. While these funds are managed to

achieve, in the long term, the target rate of return based on the discount rate specified in the ONFA, the rates of

return earned in a given period are subject to various external factors including financial market conditions and

changes in the Ontario consumer price index (CPI), which can be volatile in the short-term and cause potentially

significant short-term fluctuations in the Company’s income, net of the impact of a regulatory variance account. The

fluctuations in fund earnings are reflected in the values of the Nuclear Funds that are used to determine, in

conjunction with cost estimates for nuclear waste management and decommissioning obligations, required cash

contribution levels under the ONFA, typically every five years. The next update to the ONFA Reference Plan, which

will form the basis for required contributions for the 2017-2021 period, is expected to be effective January 1, 2017.

13

DISCUSSION OF OPERATING RESULTS BY BUSINESS SEGMENT

Regulated – Nuclear Generation Segment     Three Months Ended March 31 (millions of dollars) (unaudited) 2016 2015 Revenue 926 813 Fuel expense 81 78 Gross margin 845 735 Operations, maintenance and administration 563 526 Depreciation and amortization 230 114 Property taxes 7 7 Income before other gains, interest, and income taxes 45 88 Other gains (1) - Income before interest and income taxes 46 88

Income before interest and income taxes from the segment was $46 million during the first quarter of 2016, compared

to $88 million for the same quarter in 2015. The decrease in earnings was mainly due to an increase in nuclear

outage OM&A expenses, primarily as a result of an increase in planned outage activities during the first quarter of

2016.

The increase in segment revenue during the first quarter of 2016, compared to the same quarter in 2015, largely

reflected rate riders authorized to the end of December 31, 2016 by the OEB in October 2015. The resulting nuclear

rate rider of $10.84/MWh in effect during the first quarter of 2016 was higher than the rate rider of $1.33/MWh in

effect during the first quarter of 2015. As these rate riders allowed for the recovery of approved balances in OEB-

authorized regulatory variance and deferral accounts, the resulting increase in revenue in the first quarter of 2016

was largely offset by higher amortization expense related to the regulatory balances.

OPG revised the estimated useful lives of its nuclear generating stations for accounting purposes effective

December 31, 2015, including extensions to the useful lives of the Bruce A and Bruce B generating stations to reflect

the updated refurbishment agreement between the IESO and Bruce Power announced in December 2015. The

useful life changes resulted in an increase in OPG’s Nuclear Liabilities of $2,330 million and a corresponding

increase in the related asset retirement costs capitalized to property, plant and equipment, effective December 31,

2015. The resulting decrease in depreciation expense during the first quarter of 2016, compared to the same quarter

in 2015, was largely offset by the impact of the existing Bruce Lease Net Revenues Variance Account and the Impact

Resulting from Changes in Station End-of-Life Dates Deferral Account authorized by the OEB effective January 1,

2016. The new deferral account is discussed under the heading, Balance Sheet Highlights. Further details on

changes to the estimated useful lives of the nuclear generating stations are found in the 2015 annual MD&A in the

section, Changes in Accounting Policies and Estimates.

Segment revenue for the first quarter of 2016 reflected changes in lease and other revenues from Bruce Power

related to the Bruce nuclear generating stations arising from the December 2015 amendments to the Bruce Lease

and related agreements between OPG and Bruce Power. These changes were offset by the impact of the Bruce

Lease Net Revenues Variance Account. Details on the changes to the above agreements are found in the 2015

annual MD&A under the heading, Recent Developments.

14

The Unit Capability Factors for the Darlington and Pickering generating stations and the Nuclear TGC per MWh for

the three month periods ended were as follows:

  Three Months Ended March 31 2016 2015 Unit Capability Factor (%)

Darlington GS 97.2 97.8 Pickering GS 72.8 72.9

Nuclear TGC per MWh ($/MWh) 56.37 57.68

The slightly lower Unit Capability Factor at the Darlington GS for the three months ended March 31, 2016 reflected

the increase in planned outage days at the station. The slight decrease in the Unit Capability Factor at the Pickering

GS was due to an increase in planned outage days, partly offset by the continued improvements in reliability at the

station.

The decrease in Nuclear TGC per MWh during the first quarter of 2016, compared to the same period in 2015,

primarily reflected lower non-refurbishment capital expenditures. The definition and calculation of Nuclear TGC are

found under the heading, Supplementary Non-GAAP Financial Measures.

Regulated – Nuclear Waste Management Segment

Three Months Ended March 31 (millions of dollars) (unaudited) 2016 2015 Revenue 34 32Operations, maintenance and administration 36 34Accretion on nuclear fixed asset removal and nuclear waste management liabilities 228 220Earnings on nuclear fixed asset removal and nuclear waste (147) (231) management funds (Loss) income before interest and income taxes (83) 9 Lower earnings on the Decommissioning Fund, net of the impact of the Bruce Lease Net Revenues Variance

Account, was the primary driver for the decrease in segment earnings during the first quarter of 2016, compared to

the same quarter in 2015. The higher earnings in the first quarter of 2015 reflected stronger fund performance

compared to the same period in 2016, resulting in the Decommissioning Fund becoming over 120 percent funded

during the first quarter of 2015. Under the ONFA, if there is a surplus in the Decommissioning Fund such that the

corresponding liability, as defined by the most recently approved ONFA Reference Plan, is at least 120 percent

funded, OPG may direct up to 50 percent of the surplus over 120 percent as a contribution to the Used Fuel

Segregated Fund (Used Fuel Fund). In such cases, the Ontario Electricity Financial Corporation (OEFC) would be

entitled to a distribution of an equal amount. As a result, OPG recognized 50 percent of the surplus greater than

120 percent in income during the first quarter of 2015. As at March 31, 2016, the Decommissioning Fund was

between 100 percent and 120 percent funded and, as such, the balance of the fund recognized on the balance sheet,

net of the amount recorded as due to the Province, was equal to the cost estimate of the corresponding liability.

Lower earnings on the Used Fuel Fund, net of the impact of the Bruce Lease Net Revenues Variance Account, also

contributed to the decrease in segment earnings in the first quarter of 2016 compared to the same quarter in 2015,

primarily due to the impact of weaker market conditions on the performance of the portion of the fund not guaranteed

by the Province. This was partially offset by an increase in the CPI, which favourably impacted the CPI-adjusted rate

of return for the portion of the fund guaranteed by the Province.

15

In December 2015, OPG recognized an increase in the Nuclear Liabilities of $2,330 million, as discussed under the

heading, Regulated – Nuclear Generation Segment. As a result, higher accretion on nuclear fixed asset removal and

nuclear waste management liabilities was recognized during the first quarter of 2016, compared to the same quarter

in 2015. The increased accretion expense was largely offset by the impact of the Bruce Lease Net Revenues

Variance Account.

Regulated – Hydroelectric Segment

Three Months Ended March 31 (millions of dollars) (unaudited) 2016 2015 Revenue 1 385 394 Fuel expense 79 71 Gross margin 306 323Operations, maintenance and administration 76 76 Depreciation and amortization 56 60 Income before other gains, interest, and income taxes 174 187Other gains (22) - Income before interest and income taxes 196 187 1 During the three months ended March 31, the Regulated – Hydroelectric segment generation revenue included incentive

payments of $1 million in 2016 and $9 million in 2015 related to the OEB-approved hydroelectric incentive mechanism. The mechanism provides a pricing incentive to OPG to shift hydroelectric production from lower market price periods to higher market price periods, reducing the overall costs to customers.

The increase in segment income before interest and income taxes during the first quarter of 2016, compared to the

same quarter in 2015, was largely due to a gain of $22 million recognized during the first quarter of 2016 to reflect the

OEB’s January 2016 decision to reverse a portion of an earlier capital cost disallowance related to the Niagara

Tunnel project expenditures. The OEB’s January 2016 decision was in response to OPG’s motion that requested the

OEB to review and vary parts of its November 2014 decision that resulted in the original disallowance. The increase

in segment earnings was partly offset by a lower gross margin, net of lower depreciation and amortization expense.

Gross margin decreased by $17 million during the first quarter of 2016, compared to the same period in 2015. The

decrease was primarily due to lower hydroelectric incentive mechanism payments and lower revenue from rate riders

authorized by the OEB to the end of December 31, 2016 in October 2015. As the riders allowed for the recovery of

approved balances in OEB-authorized regulatory variance and deferral accounts, the resulting decrease in revenue

was largely offset by lower amortization expense related to the regulatory balances.

The Hydroelectric Availability and Hydroelectric OM&A Expense per MWh for the stations included in the Regulated –

Hydroelectric segment were as follows:

Three Months Ended March 31 2016 2015 Hydroelectric Availability (%) 94.8 91.5 Hydroelectric OM&A Expense per MWh ($/MWh) 9.6 9.2

The Hydroelectric Availability during the first quarter of 2016 increased, compared to the first quarter of 2015, due to

a decrease in unplanned outage days for the regulated stations. While station availability and water flows were

higher compared to the first quarter of 2015, total generation decreased due to more prevalent SBG conditions in the

province, as discussed under the heading, Electricity Generation, in the Highlights section.

The Hydroelectric OM&A Expense per MWh for the three months ended March 31, 2016 increased, compared to the

same period in 2015, as a result of the decrease in generation. During the first quarter of 2016, SBG conditions

resulted in lost generation of 1.6 TWh for the Regulated – Hydroelectric segment, compared to 0.3 TWh during the

16

first quarter of 2015. Adjusting for the foregone production due to SBG conditions in both quarters, the Hydroelectric

OM&A Expense per MWh for the segment would have decreased to $8.0/MWh for the first quarter of 2016, reflecting

an improvement compared to $8.9/MWh for the same quarter in 2015.

Contracted Generation Portfolio Segment

Three Months Ended March 31 (millions of dollars) (unaudited) 2016 2015 Revenue 145 123 Fuel expense 12 7 Gross margin 133 116 Operations, maintenance and administration 40 44 Depreciation and amortization 19 17 Accretion on fixed asset removal liabilities 2 2 Property taxes 2 2 Income from investments subject to significant influence (8) (11) Income before interest and income taxes 78 62

Income before interest and income taxes from the segment increased by $16 million during the first quarter of 2016

compared to the same period in 2015. The increase was primarily due to lower earnings in the first quarter of 2015

as a result of a provision made in that quarter related to an IESO audit.

The Hydroelectric Availability, Hydroelectric OM&A Expense per MWh, and the Thermal Equivalent Forced Outage

Rate (EFOR) for the Contracted Generation Portfolio segment were as follows:

Three Months Ended March 31 2016 2015 Hydroelectric Availability (%) 83.9 97.8 Hydroelectric OM&A Expense per MWh ($/MWh) 21.4 23.3 Thermal EFOR (%) 0.9 22.9

The Hydroelectric Availability during the first quarter of 2016 decreased compared to the same period in 2015,

primarily due to an increase in the number of planned outage days at the Harmon GS and Kipling GS on the Lower

Mattagami River.

The Hydroelectric OM&A Expense per MWh decreased during the first quarter of 2016 compared to the same quarter

in 2015, primarily as a result of a decrease in OM&A expenses for the hydroelectric stations included in the segment.

The impact of production lost due to SBG conditions on this metric for this segment was minimal for the first quarters

of 2016 and 2015.

The decrease in the Thermal EFOR during the first quarter of 2016, compared to the same quarter in 2015, was

primarily due to a fewer number of unplanned outage days at the Lennox GS.

17

Services, Trading, and Other Non-Generation Segment

Three Months Ended March 31 (millions of dollars) (unaudited) 2016 2015 Revenue 21 24 Fuel expense - 1 Gross margin 21 23 Operations, maintenance and administration 4 16 Depreciation and amortization 7 5 Accretion on fixed asset removal liabilities 2 2 Property taxes 3 4 Income (loss) before interest and income taxes 5 (4) Segment earnings increased by $9 million during the first quarter of 2016, compared to the same quarter in 2015,

reflecting higher OM&A expenses incurred in 2015 partly in relation to the Nanticoke GS prior to OPG’s decision to

proceed with the decommissioning of the station and lower staffing levels in 2016. Expenditures related to

decommissioning activities for the Nanticoke GS incurred during the first quarter of 2016 were charged against a

previously established decommissioning provision. Lower electricity trading revenue during the first quarter of 2016,

compared to the same quarter in 2015, partially offset the increase in segment earnings.

LIQUIDITY AND CAPITAL RESOURCES

OPG’s primary sources of liquidity and capital are funds generated from operations, bank financing, credit facilities

provided by the OEFC, long-term corporate debt, and capital market financing. These sources are used for multiple

purposes, including: investment in plants and technologies; major projects; funding obligations such as contributions

to the pension fund and the Nuclear Funds; payments under the OPEB plans; expenditures on fixed asset removal

and nuclear waste management activities not funded by the Nuclear Funds; and servicing and repaying long-term

debt.

Changes in cash and cash equivalents for the three months ended March 31, 2016 and 2015 were as follows: Three Months Ended March 31 (millions of dollars) (unaudited) 2016 2015 Cash and cash equivalents, beginning of period 464 610 Cash flow provided by operating activities 366 455 Cash flow used in investing activities (310) (276) Cash flow provided by (used in) financing activities 20 (255) Net increase (decrease) 76 (76) Cash and cash equivalents, end of period 540 534

For a discussion of cash flow provided by operating activities and FFO Adjusted Interest Coverage, refer to the

Highlights section.

18

Investing Activities

Electricity generation is a capital-intensive business. It requires continued investment in plants and technologies to

maintain and improve operating performance, including asset reliability, safety and environmental performance, and

generating capacity of existing stations, and to invest in the development of new generating stations and other

business growth opportunities.

Cash flow used in investing activities during the first quarter of 2016 increased by $34 million compared to the same

quarter in 2015. This increase was primarily due to higher capital expenditures for the Darlington Refurbishment

project and for the Peter Sutherland Sr. GS, which commenced construction in the second quarter of 2015.

Financing Activities

Cash flow provided by financing activities was $20 million during the first quarter of 2016, compared to cash flow

used in financing activities of $255 million during the same quarter in 2015. The cash flow used in financing activities

during the first quarter of 2015 was primarily due to long-term debt repayment of $300 million in the quarter.

OPG maintains a $1 billion revolving committed bank credit facility, which is divided into two $500 million multi-year

term tranches expiring in May 2020. OPG expects to renew and extend both tranches to May 2021 in the second

quarter of 2016. As at March 31, 2016, there were no outstanding borrowings under the bank credit facility.

As at March 31, 2016, OPG maintained $25 million of short-term, uncommitted overdraft facilities, and a further

$459 million of short-term, uncommitted credit facilities, which support the issuance of the Letters of Credit. OPG

uses Letters of Credit to support its supplementary pension plans and for other general corporate purposes. As at

March 31, 2016, a total of $389 million of Letters of Credit had been issued under these facilities. This included

$345 million for the supplementary pension plans, $43 million for general corporate purposes, and $1 million related

to the operation of the PEC.

The Company has an agreement to sell an undivided co-ownership interest in its current and future accounts

receivable to an independent trust. The maximum amount of co-ownership interest that can be sold under this

agreement is $150 million. The agreement expires on November 30, 2016. As at March 31, 2016, there were Letters

of Credit outstanding under this agreement of $150 million, which were issued in support of OPG’s supplementary

pension plans.

As at March 31, 2016, the Lower Mattagami Energy Limited Partnership (LME) maintained a $500 million bank credit

facility to support the funding requirements for the Lower Mattagami River project, including support for LME’s

commercial paper program. The facility consists of a $300 million tranche maturing in August 2020 and a

$200 million tranche maturing in August 2016. As at March 31, 2016, there was external commercial paper of

$249 million outstanding under LME’s commercial paper program. There were no amounts outstanding under LME’s

bank credit facility as at March 31, 2016.

As at March 31, 2016, OPG’s long-term debt outstanding was $5,472 million, including $323 million due within one

year. OPG continues to evaluate debt refinancing alternatives.

19

BALANCE SHEET HIGHLIGHTS

The following section provides highlights of OPG’s unaudited interim consolidated financial position using selected

balance sheet data:

As At March 31 December 31 (millions of dollars) (unaudited) 2016 2015 Property, plant and equipment - net 20,778 20,595 The increase was primarily due to capital expenditures on the Darlington Refurbishment project, partially offset by depreciation expense. Nuclear fixed asset removal and nuclear waste management funds (current 15,272 15,136 and non-current portions) The increase was primarily due to earnings on the Nuclear Funds and contributions to the Used Fuel Fund, partially offset by reimbursements of eligible expenditures on nuclear fixed asset removal and nuclear waste management activities. Fixed asset removal and nuclear waste management liabilities 20,402 20,169 The increase was primarily a result of accretion expense representing the increase in the liabilities due to the passage of time, partially offset by expenditures on nuclear fixed asset removal and waste management activities.

Impact Resulting from Changes in Station End-of-Life Dates Deferral Account

In December 2015, as required by the OEB’s previous decisions and orders, OPG applied to the OEB for an

accounting order to establish a new deferral account to record the revenue requirement impact on the prescribed

nuclear facilities of changes to the Nuclear Liabilities and depreciation expense arising from the changes in the

estimated useful lives of OPG’s nuclear stations, for accounting purposes, effective December 31, 2015.

In March 2016, the OEB issued its final decision and order establishing the requested account effective January 1,

2016. As at March 31, 2016, OPG recognized a regulatory liability of $19 million related to the balance in the deferral

account.

Further details on changes to estimated useful lives of OPG’s nuclear generating stations are found in the 2015

annual MD&A under the section, Changes in Accounting Policies and Estimates.

Off-Balance Sheet Arrangements

In the normal course of operations, OPG engages in a variety of transactions that, under US GAAP, are either not

recorded in the Company’s interim consolidated financial statements or are recorded in the Company’s interim

consolidated financial statements using amounts that differ from the full contract amounts. Principal off-balance

sheet activities for OPG include guarantees and long-term contracts.

CHANGES IN ACCOUNTING POLICIES AND ESTIMATES

OPG’s significant accounting policies are outlined in Note 3 to the audited consolidated financial statements as at and

for the year ended December 31, 2015. A discussion of recent accounting pronouncements is included in Note 2 to

OPG’s interim consolidated financial statements as at and for the three months ended March 31, 2016 under the

20

heading, Changes in Accounting Policies and Estimates. Disclosure regarding OPG’s critical accounting policies is

included in OPG’s 2015 annual MD&A.

RISK MANAGEMENT

The following provides an update to the discussion of the Company’s risks and risk management activities included in

OPG’s 2015 annual MD&A. As such, the disclosure in this section should be read in conjunction with the Risk

Management section included in the annual MD&A.

Operational Risks

Risks Associated with Existing Generating Stations

OPG is exposed to variable output from its existing generating stations that could adversely impact its financial

performance.

Pickering Extended Operations to 2024

In January 2016, the Province of Ontario announced its approval of OPG’s plan to pursue continued operation of the

Pickering GS beyond 2020 up to 2024. The current operating licence for the Pickering GS, which expires in August

2018, was issued in 2013 with the understanding that the station would shut down in 2020. Technical work

completed to date in support of continued operations to 2020 will need to be extended and expanded. This includes

completion of a Periodic Safety Review and an Integrated Implementation Plan and the submission of these

documents to the CNSC as part of the Pickering GS licence renewal application. OPG continues to prepare for the

Pickering GS licence renewal application and is conducting component condition assessments to identify the work

required to support the extended operation of the station to 2024. There is a risk that the station’s extended operation

to 2024 may be determined to be uneconomical to pursue.

Risks Associated with Major Development Projects

The risks associated with the cost, schedule, and technical aspects of the major development projects could

adversely impact OPG’s financial performance and its corporate reputation.

Nanticoke Solar Facility

In March 2016, OPG and its partners, SunEdison Canadian Construction LP and Six Nations Development

Corporation, were awarded a contract through the IESO’s LRP program to develop a 44 MW solar facility at OPG’s

Nanticoke GS site and adjacent lands. The Nanticoke solar project is subject to risks applicable to the initial stages

of project development as outlined in OPG’s 2015 annual MD&A in the Risk Management section under the heading,

Other Development Projects. OPG is also exposed to partner non-performance risk for this project. This risk is being

mitigated through partnership agreement provisions and by developing contingency plans for project execution.

Financial Risks

Commodity Markets

Changes in the market price of fuels used to produce electricity can adversely impact OPG’s earnings and cash flow

from operations.

To manage the risk of unpredictable increases in the price of fuels, the Company has fuel hedging programs, which

include fixed price and indexed contracts.

21

The percentages hedged of OPG’s fuel requirements are shown in the following table. These amounts are based on

yearly forecasts of generation and supply mix, and as such, are subject to change as these forecasts are updated.

2016 1 2017 2018

Estimated fuel requirements hedged 2 75% 75% 76% 1 Includes forecast for the remainder of the year. 2 Represents the approximate portion of megawatt-hours of expected generation production (and year-end inventory targets) from

each type of OPG-operated facility (nuclear and thermal) for which the Company has entered into contractual arrangements or obligations in order to secure the price of fuel. Excess fuel inventories in a given year are attributed to the next year for the purpose of measuring hedge ratios.

Foreign Exchange

OPG’s earnings and cash flows can be affected by movements in the United States dollar relative to the Canadian

dollar.

OPG’s financial results are exposed to volatility in the Canadian/US foreign exchange rate as fuels and certain

supplies and services purchased for generating stations and major development projects are primarily denominated

in, or tied to US dollars (USD). To manage this risk, OPG employs various financial instruments such as forwards

and other derivative contracts, in accordance with approved risk management policies. As at March 31, 2016, OPG

had foreign exchange contracts outstanding with a total notional value of USD $10 million.

Trading

OPG’s financial performance can be affected by its trading activities.

OPG’s electricity trading operations are closely monitored, with total exposures measured and reported to senior

management on a daily basis. The main metric used to measure the financial risk of trading activity is Value at Risk

(VaR). VaR is defined as a probabilistic maximum potential future loss expressed in monetary terms for a portfolio

based on normal market conditions over a set period of time. For the first quarter of 2016, the VaR utilization ranged

between $0.5 million and $1.5 million.

Credit

Deterioration in counterparty credit and non-performance by suppliers and contractors can adversely impact OPG’s

earnings and cash flows from operations.

OPG manages its exposure to suppliers or counterparties by evaluating their financial condition and negotiating

appropriate collateral or other forms of security. OPG’s credit exposure relating to energy markets transactions as at

March 31, 2016 was $556 million, including $541 million to the IESO. Management considers the Company’s risk

exposure relating to electricity sales through the IESO-administered spot market to be low as the IESO oversees the

credit worthiness of all market participants. In accordance with the IESO’s prudential support requirements, market

participants are required to provide collateral to cover funds that they might owe to the market. Over 95 percent of

the remaining $15 million exposure as at March 31, 2016 was related to investment grade counterparties.

RELATED PARTY TRANSACTIONS

Given that the Province owns all of the shares of OPG, related parties include the Province and other entities

controlled by the Province including Hydro One, the IESO, and the OEFC, and jointly controlled entities. The

transactions between OPG and related parties are measured at the exchange amount, which is the amount of

consideration established and agreed to by the related parties.  

 

22

The related party transactions are summarized below:

Three Months Ended March 31 2016 2015 (millions of dollars) (unaudited) Revenue Expense Revenue Expense Hydro One Electricity sales 2 - 6 - Services 1 5 1 2 Province of Ontario Decommissioning Fund (deficit) excess funding - (177) - 300 Used Fuel Fund rate of return guarantee - (159) - 579 Gross revenue charges - 31 - 32 ONFA guarantee fee - 2 - 2 OEFC Gross revenue charges - 37 - 39 Interest expense on long-term notes - 42 - 46 Income taxes, net of investment tax credits - 32 - 71 IESO Electricity related revenue 1,363 10 1,342 27 1,366 (177) 1,349 1,098 The receivable and payable balances between OPG and its related parties are summarized below:

March 31 December 31 (millions of dollars) (unaudited) 2016 2015 Receivables from related parties Hydro One - 1 IESO 541 531 OEFC 4 9 PEC 3 3 Province of Ontario 1 1 Accounts payable and accrued charges Hydro One - 1 OEFC 28 51 Province of Ontario 13 20 IESO 1 18

INTERNAL CONTROLS OVER FINANCIAL REPORTING AND DISCLOSURE CONTROLS

During the most recent interim period, there have been no changes in the Company’s policies, procedures and

processes that comprise its internal controls over financial reporting that have materially affected, or are reasonably

likely to materially affect, the Company’s internal control over financial reporting.

23

QUARTERLY FINANCIAL HIGHLIGHTS

The following tables set out selected financial information from OPG’s unaudited interim consolidated financial

statements for each of the eight most recently completed quarters.

(millions of dollars - except where noted) March 31 December 31 September 30 June 30 (unaudited) 2016 2015 2015 2015 Revenue 1,478 1,312 1,426 1,383Net income (loss) attributable to the 123 (101) 80 189

Shareholder Net income attributable to non-controlling 5 1 5 4

interest Net income (loss) 128 (100) 85 193 Per common share, $0.48 ($0.39) $0.31 $0.74

attributable to the Shareholder (dollars)

   

(millions of dollars - except where noted) March 31 December 31 September 30 June 30 (unaudited) 2015 2014 2014 2014

Revenue 1,355 1,318 1,160 1,098Income before extraordinary item attributable to the Shareholder 234 86 118 115Income before extraordinary item attributable to non-controlling interest 5 4 1 1Income before extraordinary item 239 90 119 116

Net income attributable to the Shareholder 234 86 361 115Net income attributable to non-controlling interest 5 4 1 1Net income 239 90 362 116

Per common share, attributable to the Shareholder (dollars)

Income before extraordinary item $0.91 $0.34 $0.46 $0.45

Net income $0.91 $0.34 $1.41 $0.45

Trends

OPG’s quarterly results are affected by changes in grid-supplied electricity demand primarily resulting from variations

in seasonal weather conditions, changes in economic conditions, the impact of small scale generation embedded in

distribution networks, and the impact of conservation efforts in the province. Weather conditions affect water flows,

electricity demand, and prevalence of SBG conditions. Historically, OPG’s revenues are higher in the first quarter of

a fiscal year as a result of winter heating demands and in the third quarter due to air conditioning and cooling

demands. With respect to regulated hydroelectric operations, the financial impact of foregone production due to SBG

conditions and the financial impact of differences between forecast water flows reflected in OEB-approved regulated

prices and the actual water flows are offset by regulatory variance accounts authorized by the OEB. OPG’s financial

results are also affected by the earnings on the Nuclear Funds, net of the impact of the Bruce Lease Net Revenues

Variance Account.

24

  

Additional items that affected net income in certain quarters above are described in OPG’s 2015 annual MD&A under

the heading, Quarterly Financial Highlights.

SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES

In addition to providing net income and other financial information in accordance with US GAAP, certain non-GAAP

financial measures are also presented in OPG’s MD&A. These non-GAAP measures do not have any standardized

meaning prescribed by US GAAP and, therefore, may not be comparable to similar measures presented by other

issuers. OPG utilizes these measures to make operating decisions and assess performance. Readers of the MD&A

would utilize these measures in assessing the Company’s financial performance from ongoing operations. The

Company believes that these indicators are important since they provide additional information about OPG’s

performance, facilitate comparison of results over different periods, and present measures consistent with the

Company’s strategies to provide value to the Shareholder and to ensure availability of cost effective funding. These

non-GAAP financial measures have not been presented as an alternative to net income, cash flows from operations,

or any other measure in accordance with US GAAP, but as an indicator of operating performance.

*net of regulatory variance account

25

The definitions of the non-GAAP financial measures are as follows:

(1) ROE Excluding AOCI is defined as net income attributable to the Shareholder divided by average equity

attributable to the Shareholder excluding AOCI, for the period. ROE Excluding AOCI is measured over a 12-month

period and is calculated as follows:

Twelve Months Ended

March 31 December 31 (millions of dollars – except where noted) (unaudited) 2016 2015 ROE Excluding AOCI Net income attributable to the Shareholder 291 402 Divided by: Average equity attributable to the Shareholder, excluding AOCI 10,202 10,023 ROE Excluding AOCI (percent) 2.9 4.0

(2) FFO Adjusted Interest Coverage is defined as FFO before interest divided by adjusted interest expense. FFO

before interest is defined as cash flow provided by operating activities adjusted for interest paid, interest capitalized to

fixed and intangible assets, and changes to non-cash working capital balances for the period. Adjusted interest

expense is calculated as net interest expense plus interest income, interest capitalized to fixed and intangible assets,

interest related to regulatory assets and liabilities, and interest on pension and OPEB projected benefit obligations

less expected return on pension plan assets, for the period.

FFO Adjusted Interest Coverage is measured over a 12-month period and is calculated as follows:

Twelve Months Ended March 31 December 31 (millions of dollars – except where noted) (unaudited) 2016 2015 FFO before interest Cash flow provided by operating activities 1,376 1,465 Add: Interest paid 261 269 Less: Interest capitalized to fixed and intangible assets (110) (102) Add: Changes to non-cash working capital balances 255 100 FFO before interest 1,782 1,732 Adjusted interest expense Net interest expense 166 180 Add: Interest income 8 9 Add: Interest capitalized to fixed and intangible assets 110 102 Add: Interest related to regulatory assets and liabilities 9 2 Add: Interest on pension and OPEB projected benefit obligations 51 53 less expected return on pension plan assets Adjusted interest expense 344 346 FFO Adjusted Interest Coverage (times) 5.2 5.0

(3) Nuclear Total Generating Cost per MWh is used to measure the cost performance of OPG’s nuclear generating

assets. Nuclear TGC per MWh is defined as the total of OM&A expenses of the Regulated – Nuclear Generation

segment (excluding Darlington Refurbishment project costs, the impact of regulatory variance and deferral accounts,

and expenses ancillary to the nuclear electricity generation business), nuclear fuel expense for OPG-operated

stations (excluding the impact of regulatory variance and deferral accounts), and capital expenditures of the

Regulated – Nuclear Generation segment (excluding Darlington Refurbishment project costs) incurred in the period,

divided by OPG’s nuclear electricity generation.

26

Three Months Ended March 31 (millions of dollars – except where noted) (unaudited) 2016 2015 Nuclear TGC Regulated – Nuclear Generation OM&A expenses 563 526 Regulated – Nuclear Generation fuel expense 81 78 Regulated – Nuclear Generation capital expenditures 249 214 Less: Darlington Refurbishment project capital and non-capital costs (205) (156) Add: Regulated – Nuclear Generation OM&A and fuel expenses deferred in 24 57 regulatory variance and deferral accounts Less: Nuclear fuel expense for non OPG-operated stations (17) (17) Other adjustments (2) 2 Nuclear TGC 693 704

Nuclear electricity generation (TWh) 12.3 12.2 Nuclear TGC per MWh ($/MWh) 1 56.37 57.68 1 Amount may not calculate due to rounding.

(4) Gross margin is defined as revenue less fuel expense.

Additional information about OPG, including its 2015 annual MD&A, and audited annual consolidated financial

statements as at and for the year ended December 31, 2015 and notes thereto, can be found on SEDAR at

www.sedar.com.

For further information, please contact: Investor Relations 416-592-6700

1-866-592-6700

investor.relations@opg.com

Media Relations 416-592-4008 1-877-592-4008 www.opg.com www.sedar.com

ONTARIO POWER GENERATION INC.

INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

MARCH 31, 2016

 

1

INTERIM CONSOLIDATED STATEMENTS OF INCOME(UNAUDITED)

Three Months Ended March 31 (millions of dollars except where noted) 2016 2015 Revenue (Note 12) 1,478 1,355 Fuel expense (Note 12) 172 157 Gross margin (Note 12) 1,306 1,198 Expenses (Note 12) Operations, maintenance and administration 686 665 Depreciation and amortization 312 196 Accretion on fixed asset removal and nuclear waste management liabilities 232 224 Earnings on nuclear fixed asset removal and nuclear waste management funds (147) (231) Property taxes 12 13 Income from investments subject to significant influence (8) (11) 1,087 856 Income before other gains, interest, and income taxes 219 342 Other gains (Note 2) (23) - Income before interest and income taxes 242 342 Net interest expense (Note 5) 33 47 Income before income taxes 209 295 Income tax expense 81 56 Net income 128 239 Net income attributable to the Shareholder 123 234 Net income attributable to non-controlling interest 5 5 Basic and diluted net income per common share (dollars) 0.48 0.91 Common shares outstanding (millions) 256.3 256.3 See accompanying notes to the interim consolidated financial statements

  

2

INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Three Months Ended March 31 (millions of dollars) 2016 2015 Net income 128 239 Other comprehensive income, net of income taxes (Note 7) Net gain on derivatives designated as cash flow hedges - 1 Reclassification to income of losses from cash flow hedges 1 4 3 Reclassification to income of amounts related to pension 3 5 and other post-employment benefits 1 Other comprehensive income for the period 7 9 Comprehensive income 135 248 Comprehensive income attributable to the Shareholder 130 243 Comprehensive income attributable to non-controlling interest 5 5 1 Net of income tax expenses of $1 million for the three months ended March 31, 2016 and 2015.

See accompanying notes to the interim consolidated financial statements

3

INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Three Months Ended March 31 (millions of dollars) 2016 2015 Operating activities Net income 128 239 Adjust for non-cash items: Depreciation and amortization 312 196 Accretion on fixed asset removal and nuclear waste management liabilities 232 224 Earnings on nuclear fixed asset removal and nuclear waste management funds (147) (231) Pension and other post-employment benefit costs (Note 8) 117 120 Mark-to-market on derivative instruments 3 44 Provision for used nuclear fuel and low and intermediate level waste 33 29 Regulatory assets and liabilities (12) (28) Provision for materials and supplies 4 7 Other gains (Note 2) (23) - Other (3) (13) 644 587 Contributions to nuclear fixed asset removal and nuclear waste (37) (35) management funds Expenditures on fixed asset removal and nuclear waste management (58) (46) Reimbursement of expenditures on nuclear fixed asset removal 15 22 and nuclear waste management Contributions to pension funds and expenditures on other post-employment (116) (122) benefits and supplementary pension plans Expenditures on restructuring (2) (6) Net changes to other long-term assets and liabilities 42 20 Net changes to non-cash working capital balances (Note 13) (122) 35 Cash flow provided by operating activities 366 455 Investing activities Proceeds from deposit note 10 - Investment in property, plant and equipment and intangible assets (320) (276) Cash flow used in investing activities (310) (276) Financing activities Repayment of long-term debt - (300) Distribution paid to non-controlling interest (4) (5) Issuance of short-term debt 1,010 990 Repayment of short-term notes (986) (940) Cash flow provided by (used in) financing activities 20 (255) Net increase (decrease) in cash and cash equivalents 76 (76) Cash and cash equivalents, beginning of period 464 610 Cash and cash equivalents, end of period 540 534 See accompanying notes to the interim consolidated financial statements

4

INTERIM CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As at March 31 December 31 (millions of dollars) 2016 2015 Assets Current assets Cash and cash equivalents 540 464 Receivables from related parties 549 545 Other current assets 363 298 Nuclear fixed asset removal and nuclear waste management funds 15 15 Fuel inventory 333 344 Materials and supplies 95 96 Regulatory assets (Note 3) 471 628 2,366 2,390 Property, plant and equipment 29,798 29,469 Less: accumulated depreciation 9,020 8,874 20,778 20,595 Intangible assets 485 476 Less: accumulated amortization 384 378 101 98 Other assets Nuclear fixed asset removal and nuclear waste management funds 15,257 15,121 Long-term materials and supplies 336 337 Regulatory assets (Note 3) 5,304 5,240 Investments subject to significant influence (Note 14) 326 336 Other long-term assets 78 133 21,301 21,167 44,546 44,250 See accompanying notes to the interim consolidated financial statements

5

INTERIM CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As at March 31 December 31 (millions of dollars) 2016 2015 Liabilities Current liabilities Accounts payable and accrued charges 1,083 1,199 Deferred revenue due within one year 12 12 Long-term debt due within one year (Note 4) 323 273 Short-term debt (Note 5) 249 225 Regulatory liabilities (Note 3) 20 26 Income tax payable 81 66 1,768 1,801 Long-term debt (Note 4) 5,136 5,186 Other liabilities Fixed asset removal and nuclear waste management liabilities (Note 6) 20,402 20,169 Pension liabilities 2,550 2,597 Other post-employment benefit liabilities 3,115 3,085 Long-term accounts payable and accrued charges 208 207 Deferred revenue 259 246 Deferred income taxes 836 880 Regulatory liabilities (Note 3) 96 34 27,466 27,218 Equity Common shares 1 5,126 5,126 Retained earnings 5,221 5,098 Accumulated other comprehensive loss (Note 7) (312) (319) Equity attributable to the Shareholder 10,035 9,905 Equity attributable to non-controlling interest 141 140 Total Equity 10,176 10,045 44,546 44,250 1 256,300,010 common shares outstanding at a stated value of $5,126 million as at March 31, 2016 and December 31, 2015.

Commitments and Contingencies (Notes 4, 10 and 11)

See accompanying notes to the interim consolidated financial statements

6

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)

Three Months Ended March 31 (millions of dollars) 2016 2015 Common shares 5,126 5,126 Retained earnings Balance at beginning of period 5,098 4,696 Net income attributable to the Shareholder 123 234 Balance at end of period 5,221 4,930 Accumulated other comprehensive loss, net of income taxes Balance at beginning of period (319) (496) Other comprehensive income 7 9 Balance at end of period (312) (487) Equity attributable to the Shareholder 10,035 9,569 Equity attributable to non-controlling interests Balance at beginning of period 140 141 Distribution to non-controlling interests (4) (5) Net income attributable to non-controlling interest 5 5 Balance at end of period 141 141 Total equity 10,176 9,710 See accompanying notes to the interim consolidated financial statements

7

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) For the three months ended March 31, 2016 and 2015

1. BASIS OF PRESENTATION

These interim consolidated financial statements for the three months ended March 31, 2016 and 2015 include the

accounts of Ontario Power Generation Inc. (OPG or Company) and its subsidiaries. The Company consolidates its

interest in entities over which it is able to exercise control and attributes the results to its sole shareholder, the

Province of Ontario (Province). Interests owned by other parties are reflected as non-controlling interest. These

interim consolidated financial statements have been prepared and presented in accordance with United States

generally accepted accounting principles (US GAAP) and the rules and regulations of the United States (US)

Securities and Exchange Commission for interim financial statements. These interim consolidated financial

statements do not contain all of the disclosures required by US GAAP for annual financial statements. Accordingly,

they should be read in conjunction with the annual consolidated financial statements of the Company as at and for

the year ended December 31, 2015. All dollar amounts are presented in Canadian dollars.

Certain of the 2015 comparative amounts have been reclassified from financial statements previously presented to

conform to the 2016 interim consolidated financial statement presentation.

Use of Management Estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and

assumptions that affect the reported amounts of assets and liabilities at the date of the interim consolidated financial

statements, and the reported amounts of revenues and expenses during the reporting periods. Management

evaluates the Company’s estimates on an ongoing basis based on historical experience, current conditions and

assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in the

period incurred. Significant estimates are included in the determination of pension and other post-employment

benefits (OPEB) liabilities, asset retirement obligations, income taxes (including deferred income taxes),

contingencies, regulatory assets and liabilities, valuation of derivative instruments, depreciation and amortization, and

inventories. Actual results may differ significantly from these estimates.

2. CHANGES IN ACCOUNTING POLICIES AND ESTIMATES

Recent Accounting Pronouncements

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share

In May 2015, the Financial Accounting Standards Board issued Accounting Standards Update No. 2015-07, Fair

Value Measurement (Topic 820) – Disclosures for Investments in Certain Entities That Calculate Net Asset Value per

Share (or its Equivalent). Under the new guidance, investments measured at net asset values, which have been

elected under the guidance as a practical expedient for fair value, are excluded from the fair value hierarchy.

Removing investments measured using the practical expedient from the fair value hierarchy is intended to eliminate

the diversity in practice that currently exists with respect to the categorization of these investments. The only criterion

for categorizing investments in the fair value hierarchy is the observability of the inputs. OPG has adopted the

updates to Accounting Standards Codification (ASC) Topic 820, Fair Value Measurement for the March 31, 2016

interim consolidated financial statements. The change in disclosures required under this update are reflected in

Note 10. 

8

Changes in Accounting Policies and Estimates

In January 2016, the Ontario Energy Board (OEB) issued its decision on OPG’s December 2014 motion that

requested the OEB to review and vary parts of its November 2014 decision, including the disallowed Niagara Tunnel

project capital costs. In its January 2016 decision, the OEB reversed a portion of the November 2014 Niagara Tunnel

capital cost disallowance and established a new variance account to record the revenue requirement impact of the

reversed disallowance effective November 1, 2014. The November 2014 disallowance resulted in a write off of

capital costs in the fourth quarter of 2014. To recognize the expected future recovery of the reversed portion of the

disallowance and related revenue requirement impact to March 31, 2016, during the first quarter of 2016, OPG

recorded an increase to property, plant and equipment and a corresponding gain of $22 million, and a regulatory

asset of $2 million related to the balance in the variance account, in accordance with ASC Topic 980, Regulated

Operations.

3. REGULATORY ASSETS AND LIABILITIES

The regulatory assets and liabilities recorded as at March 31, 2016 and December 31, 2015 are as follows:

March 31 December 31(millions of dollars) 2016 2015 Regulatory assets Variance and deferral accounts as authorized by the OEB Pension and OPEB Cost Variance Account 828 865 Pension & OPEB Cash Versus Accrual Differential Deferral Account (Note 8) 349 315 Hydroelectric Surplus Baseload Generation Variance Account 155 114 Nuclear Liability Deferral Account 143 190 Bruce Lease Net Revenues Variance Account 120 95 Nuclear Deferral and Variance Over/Under Recovery Variance Account 68 82 Other variance and deferral accounts 27 53 1,690 1,714

Pension and OPEB Regulatory Asset (Note 8) 3,312 3,362 Deferred Income Taxes 773 792 Total regulatory assets 5,775 5,868 Less: current portion 471 628 Non-current regulatory assets 5,304 5,240 Regulatory liabilities Variance and deferral accounts as authorized by the OEB Other variance and deferral accounts 116 60 Total regulatory liabilities 116 60 Less: current portion 20 26 Non-current regulatory liabilities 96 34 In December 2015, as required by the OEB’s previous decisions and orders, OPG applied to the OEB for an

accounting order to establish a new deferral account to record the revenue requirement impact on the prescribed

nuclear facilities of changes to the nuclear fixed asset removal and nuclear waste management liabilities and

depreciation expense arising from the changes in the estimated useful lives of the Company’s nuclear stations, for

accounting purposes, effective December 31, 2015.

9

In March 2016, the OEB issued its final decision and order establishing the requested account, the Impact Resulting

from Changes in Station-End-of-Life Dates Deferral Account, effective January 1, 2016. As at March 31, 2016, OPG

recognized a regulatory liability of $19 million related to the balance in the deferral account. Details of the changes to

the estimated useful lives of OPG’s nuclear generating stations that gave rise to this deferral account are found in

Note 3 to the annual consolidated financial statements of the Company as at and for the year ended December 31,

2015.

As at March 31, 2016 and December 31, 2015, regulatory assets for other variance and deferral accounts included

amounts for the Pension & OPEB Cash Payment Variance Account, the Hydroelectric Deferral and Variance

Over/Under Recovery Variance Account, the Pickering Life Extension Depreciation Variance Account, the Nuclear

Development Variance Account, and the Capacity Refurbishment Variance Account. As at March 31, 2016 and

December 31, 2015, regulatory liabilities for other variance and deferral accounts included the Hydroelectric Water

Conditions Variance Account, the Ancillary Services Net Revenue Variance Account, the Income and Other Taxes

Variance Account, and the Hydroelectric Incentive Mechanism Variance Account.

As at March 31, 2016, regulatory assets for other variance and deferral accounts also included the Niagara Tunnel

Project Pre-December 2008 Disallowance Variance Account and regulatory liabilities for other variance and deferral

accounts also included the Impact Resulting from Changes in Station-End-of-Life Dates Deferral Account.

4. LONG-TERM DEBT

Long-term debt consists of the following:

March 31 December 31(millions of dollars) 2016 2015 Notes payable to the Ontario Electricity Financial Corporation 3,465 3,465 UMH Energy Partnership 187 187 PSS Generating Station Limited Partnership 245 245 Lower Mattagami Energy Limited Partnership 1,575 1,575 5,472 5,472Less: bond issuance fees (13) (13) Less: due within one year (323) (273) Long-term debt 5,136 5,186 During the first quarter of 2016, no long-term debt was repaid (three months ended March 31, 2015 – $300 million).

5. SHORT-TERM DEBT AND NET INTEREST EXPENSE

OPG maintains a $1 billion revolving committed bank credit facility, which is divided into two $500 million multi-year

term tranches, expiring in May 2020. As at March 31, 2016, there were no outstanding borrowings under the bank

credit facility.

As at March 31, 2016, the Lower Mattagami Energy Limited Partnership (LME) maintained a $500 million bank credit

facility to support the funding requirements for the Lower Mattagami River project, including support for LME’s

commercial paper program. The facility consists of a $300 million tranche maturing in August 2020 and a

$200 million tranche maturing in August 2016. As at March 31, 2016, there was external commercial paper of

$249 million outstanding under LME’s commercial paper program (December 31, 2015 – $225 million). There were

no amounts outstanding under LME’s bank credit facility as at March 31, 2016.

10

The following table summarizes net interest expense:

Three Months Ended March 31 (millions of dollars) 2016 2015 Interest on long-term debt 72 72 Interest on short-term debt 1 1 Interest income (2) (3) Interest capitalized to property, plant and equipment, and intangible assets (31) (23) Interest related to regulatory assets and liabilities 1 (7) - Net interest expense 33 47 1 Includes interest to recognize the cost of financing related to regulatory variance and deferral accounts, as authorized by the

OEB, and interest deferred in the Capacity Refurbishment Variance Account and the Bruce Lease Net Revenues Variance Account.

6. FIXED ASSET REMOVAL AND NUCLEAR WASTE MANAGEMENT LIABILITIES

The liabilities for fixed asset removal and nuclear waste management on a present value basis as at March 31, 2016

and December 31, 2015 consist of the following:

March 31 December 31(millions of dollars) 2016 2015 Liability for nuclear used fuel management 12,957 12,793 Liability for nuclear decommissioning and low and intermediate 7,066 6,999 level waste management Liability for non-nuclear fixed asset removal 379 377 Fixed asset removal and nuclear waste management liabilities 20,402 20,169

7. ACCUMULATED OTHER COMPREHENSIVE LOSS

The changes in the balance of each component of accumulated other comprehensive loss (AOCL), net of income

taxes, are as follows:

Three Months Ended March 31, 2016 Unrealized Gains and Losses on Cash Pension and (millions of dollars) Flow Hedges 1 OPEB 1 Total 1 AOCL, beginning of period (106) (213) (319) Amounts reclassified from AOCL 4 3 7 AOCL, end of period (102) (210) (312)1 All amounts are net of income taxes.

11

Three Months Ended March 31, 2015 Unrealized Gains and Losses on Cash Pension and (millions of dollars) Flow Hedges 1 OPEB 1 Total 1 AOCL, beginning of period (117) (379) (496)

Net gain from cash flow hedges 1 - 1 Amounts reclassified from AOCL 3 5 8 Other comprehensive income for the period 4 5 9 AOCL, end of period (113) (374) (487) 1 All amounts are net of income taxes.

The significant amounts reclassified out of each component of AOCL, net of income taxes, during the three months ended March 31, 2016 and 2015 are as follows:

Amount Reclassified from AOCL (millions of dollars) 2016 1 2015 1 Statement of Income Line Item Amortization of losses from cash flow hedges Losses 4 3 Net interest expense and fuel expense

Amortization of amounts related to pension and other post-employment benefits Net actuarial loss 3 5 See (2) below Total reclassifications for the period 7 8 1 All amounts are net of income taxes. 2 These AOCL components are included in the computation of pension and OPEB costs (see Note 8 for additional details).

8. PENSION AND OPEB

OPG’s pension and OPEB costs for the three months ended March 31, 2016 and 2015 are as follows:

Registered Pension Supplementary Plans Pension Plans OPEB (millions of dollars) 2016 2015 2016 2015 2016 2015 Components of Cost Recognized Current service costs 69 80 2 2 17 18 Interest on projected benefit obligation 158 157 3 3 33 32 Expected return on plan assets, net of expenses (183) (179) - - - - Amortization of net actuarial loss 1 48 73 1 1 5 7 Cost recognized 2 92 131 6 6 55 57 1 The amortization of net actuarial loss is recognized as an increase to other comprehensive income. This increase in the first

quarter of 2016 was partially offset by a decrease in the Pension and OPEB Regulatory Asset of $50 million (three months ended March 31, 2015 – $75 million).

2 These pension and OPEB costs for the three months ended March 31, 2016 exclude the reduction of costs resulting from the recognition of additions to the regulatory assets for the Pension & OPEB Cash Versus Accrual Differential Deferral Account and the Pension & OPEB Cash Payment Variance Account of $34 million and $2 million, respectively (three months ended March 31, 2015 – $67 million and $7 million, respectively).

 

12

9. RISK MANAGEMENT AND DERIVATIVES

OPG is exposed to risks related to changes in market interest rates on debt expected to be issued in the future and

movements in foreign currency that affect the Company’s assets, liabilities, and forecasted transactions. Select

derivative instruments are used to manage such risks. Derivatives are used as hedging instruments, as well as for

trading purposes.

Interest rate risk is the risk that the value of assets and liabilities can change due to movements in related interest

rates. Interest rate risk for OPG arises with the need to refinance existing debt and/or undertake new financing. The

management of these risks includes using derivatives to hedge the exposure in accordance with corporate risk

management policies. OPG periodically uses interest rate swap agreements to mitigate elements of interest rate risk

exposure associated with anticipated financing.

OPG’s financial results are exposed to volatility in the Canadian/US foreign exchange rate as fuels and certain

supplies and services purchased for generating stations and major development projects are primarily denominated

in, or tied to US dollars. OPG enters into foreign exchange derivatives and agreements with major financial

institutions, when appropriate, in order to manage the Company’s exposure to foreign currency movements.

The majority of OPG’s revenues are derived from sales through the Independent Electricity System Operator (IESO)

administered spot market. Market participants in the IESO spot market provide collateral in accordance with the

IESO prudential support requirements to cover funds that they might owe to the market. Although the credit exposure

to the IESO represents a significant portion of OPG’s accounts receivable, the Company’s management accepts this

risk due to the IESO’s primary role in the Ontario electricity market. The remaining receivables exposure is to a

diverse group of generally high quality counterparties. OPG’s allowance for doubtful accounts as at March, 2016 was

less than $1 million. OPG’s fair value derivatives totalled a net liability of $13 million as at March 31, 2016

(December 31, 2015 – $2 million).

Existing net losses of $21 million related to unrealized gains and losses on cash flow hedges deferred in AOCL as at

March 31, 2016 are expected to be reclassified to net income within the next 12 months. 

10. FAIR VALUE MEASUREMENTS

The fair value of financial instruments traded in active markets is based on quoted market prices at the consolidated

balance sheet dates. A market is regarded as active if quoted prices are readily and regularly available from an

exchange, dealer, broker, industry group, pricing service, or regulatory agency, and those prices represent actual and

regularly occurring market transactions on an arm’s length basis. The quoted market price used for financial assets

held by OPG is the current bid price. These instruments are included in Level 1 of the fair value hierarchy and are

comprised primarily of equity investments and fund investments. The fair value hierarchy groups financial

instruments into three levels, based on the significance of inputs used in measuring the fair value of the assets and

liabilities.

For financial instruments which do not have quoted market prices directly available, fair values are estimated using

forward price curves developed from observable market prices or rates. The estimate of fair value may include the

use of valuation techniques or models, based wherever possible on assumptions supported by observable market

prices or rates prevailing at the dates of the interim consolidated balance sheets. This is the case for over-the-

counter derivatives and securities, which include energy commodity derivatives, foreign exchange derivatives,

interest rate swap derivatives, and fund investments. Pooled fund investments are valued at the unit values supplied

by the pooled fund administrators. The unit values represent the underlying net assets at fair values, determined

using closing market prices. Valuation models use general assumptions and market data and therefore do not reflect

the specific risks and other factors that would affect a particular instrument’s fair value. The methodologies used for

calculating the fair value adjustments are reviewed on an ongoing basis to ensure that they remain appropriate. If all

13

significant inputs required to measure an instrument at fair value are observable, the instrument is included in

Level 2 of the fair value hierarchy.

If one or more of the significant inputs is not based on observable market data, the instrument is included in Level 3

of the fair value hierarchy. Specific valuation techniques are used to value these instruments. Significant Level 3

inputs include recent comparable transactions, comparable benchmark information, bid/ask spread of similar

transactions, and other relevant factors.

Certain alternative investments are measured at fair value by their investment managers using net asset value (NAV).

Investments measured at NAV as a practical expedient for determining their fair value are excluded from the fair

value hierarchy.

The following is a summary of OPG’s financial instruments and their fair value as at March 31, 2016 and December 31, 2015:   Fair Carrying Value Value 1 (millions of dollars) 2016 2015 2016 2015 Balance Sheet Line Item Nuclear Funds 15,272 15,136 15,272 15,136 Nuclear fixed asset removal (includes current portion) 2 and nuclear waste management funds Payable related to cash flow (54) (56) (54) (56) Long-term accounts payable hedges and accrued charges Long-term debt (includes (6,068) (5,978) (5,472) (5,472) Long-term debt current portion) Other financial instruments (6) 6 (6) 6 Various 1 The carrying values of other financial instruments included in cash and cash equivalents, receivables from related parties, other

short-term assets, short-term debt, and accounts payable and accrued charges approximate their fair value due to the immediate or short-term maturity of these financial instruments.

2 The Nuclear Funds are comprised of the Decommissioning Segregated Fund (Decommissioning Fund) and the Used Fuel Segregated Fund (Used Fuel Fund).

  The fair value of long-term debt instruments is determined based on a conventional pricing model, which is a function

of future cash flows, the current market yield curve and term to maturity. These inputs are considered to be Level 2

inputs.

14

The following tables present financial assets and liabilities measured at fair value in accordance with the fair value hierarchy as at March 31, 2016 and December 31, 2015:

March 31, 2016 (millions of dollars) Level 1 Level 2 Level 3 Total Assets Used Fuel Fund Investments measured at fair value, excluding 4,841 4,458 - 9,299

investments measured at NAV 1 Investments measured at NAV 1 894 10,193Due to Province (1,544) Used Fuel Fund, net 8,649 Decommissioning Fund Investments measured at fair value, excluding 3,665 3,320 - 6,985

investments measured at NAV 1 Investments measured at NAV 1 746 7,731Due to Province (1,108) Decommissioning Fund, net 6,623 Other financial assets 14 4 11 29 Liabilities Other financial liabilities (23) (11) (1) (35) 1 Investments measured at fair value using NAV as a practical expedient have not been classified in the fair value hierarchy. The

fair value amounts for these investments presented in this table are intended to permit the reconciliation of the fair value hierarchy to amounts presented on the interim consolidated balance sheets.

December 31, 2015 (millions of dollars) Level 1 Level 2 Level 3 Total Assets Used Fuel Fund Investments measured at fair value, excluding 5,022 4,385 - 9,407

investments measured at NAV 1 Investments measured at NAV 1 883 10,290Due to Province (1,703) Used Fuel Fund, net 8,587 Decommissioning Fund Investments measured at fair value, excluding 3,828 3,269 - 7,097

investments measured at NAV 1 Investments measured at NAV 1 737 7,834Due to Province (1,285) Decommissioning Fund, net 6,549 Other financial assets 14 4 16 34 Liabilities Other financial liabilities (18) (8) (2) (28) 1 Investments measured at fair value using NAV as a practical expedient have not been classified in the fair value hierarchy. The

fair value amounts for these investments presented in this table are intended to permit the reconciliation of the fair value hierarchy to amounts presented on the interim consolidated balance sheets.

15

During the three months ended March 31, 2016, there were no transfers between Level 1 and Level 2. In addition,

there were no transfers into and out of Level 3.

The following tables present the changes in OPG's assets and liabilities measured at fair value that are classified as Level 3 for the three months ended March 31, 2016:

Other financial (millions of dollars) instruments Opening balance, January 1, 2016 14 Realized losses included in revenue (5) Purchases 1 Closing balance, March 31, 2016 10 Nuclear Funds

The fair value of the investments within the Nuclear Funds’ alternative investment portfolio is determined using

appropriate valuation techniques, such as recent arm’s length market transactions, references to current fair values of

other instruments that are substantially the same, discounted cash flow analyses, third-party independent appraisals,

valuation multiples, or other valuation methods. Any control, size, liquidity or other discount premiums on the

investments are considered in the determination of fair value.

The process of valuing investments for which no published market price exists is based on inherent uncertainties and

the resulting values may differ from values that would have been used had a ready market existed for these

investments. The values may also differ from the prices at which the investments may be sold.

The following are the classes of investments within the Nuclear Funds that are reported on the basis of NAV

as at March 31, 2016:

Fair Unfunded Redemption Redemption (millions of dollars except where noted) Value Commitments Frequency Notice Infrastructure 981 317 n/a n/a Real Estate 611 218 n/a n/a Agriculture 48 141 n/a n/a Pooled Funds Short-term Investments 28 n/a Daily 1 - 5 Days Fixed Income 625 n/a Daily 1 - 5 Days Equity 681 n/a Daily 1 - 5 Days Total 2,974 676 The fair value of the pooled funds is classified as Level 2. Infrastructure, real estate and agriculture investments

are measured using NAV as a practical expedient for determining their fair value. Infrastructure

This class includes investments in funds whose investment objective is to generate a combination of long-term capital

appreciation and current income, generally through investments such as energy, transportation and utilities. The fair

values of investments in this class have been estimated using the NAV of the Nuclear Funds’ ownership interest in

partners’ capital and/or underlying investments held by subsidiaries of an infrastructure fund. The investments in the

respective infrastructure funds are not redeemable. However, the Nuclear Funds may transfer any of its partnership

interests/shares to another party, as stipulated in the partnership agreements and/or shareholders’ agreements.

Distributions from each infrastructure fund will be received based on the operations of the underlying investments

and/or as the underlying investments of the infrastructure funds are liquidated. It is not possible to estimate when the

16

underlying assets of the infrastructure funds will be liquidated. However, the infrastructure funds have a maturity end

period ranging from 2019 to 2025.

Real Estate

This class includes investment in institutional-grade real estate property located in Canada. The investment objective

is to provide a stable level of income with the opportunity for long-term capital appreciation. The fair values of the

investments in this class have been estimated using the NAV of the Nuclear Funds’ ownership interest in these

investments. The partnership investments are not redeemable. However, the Nuclear Funds may transfer any of its

partnership interests to another party, as stipulated in the partnership agreement. For investments in private real

estate corporations, shares may be redeemed through a pre-established redemption process. It is not possible to

estimate when the underlying assets in this class will be liquidated.

Agriculture

This class includes a diversified portfolio of global farmland and timberland investments. The investment objective is

to provide a differentiated return source, income yield, and inflation protection. The fair values of the investments in

this class have been estimated using the NAV of the Nuclear Funds’ ownership interest in these investments. The

investments are not redeemable. However, the Nuclear Funds may transfer any of its partnership interests/shares to

another party, as stipulated in the partnership agreements and/or shareholders’ agreements.

Pooled Funds

This class represents investments in pooled funds, which primarily include a diversified portfolio of fixed income

securities, issued mainly by Canadian corporations and diversified portfolios of Emerging Market listed equity. The

investment objective of the pooled funds is to achieve capital appreciation and income through professionally

managed portfolios. The fair value of the investments in this class has been estimated using the NAV per share of

the investments. There are no significant restrictions on the ability to sell the investments in this class.

11. COMMITMENTS AND CONTINGENCIES

Litigation

On August 9, 2006, a Notice of Action and Statement of Claim filed with the Ontario Superior Court of Justice in the

amount of $500 million was served against OPG and Bruce Power L.P. (Bruce Power) by British Energy Limited and

British Energy International Holdings Limited (together British Energy). The action is for contribution and indemnity of

any amounts British Energy was liable for in an arbitration against it by some of the owners of Bruce Power regarding

an alleged breach of British Energy’s representations and warranties to the claimants when they purchased British

Energy’s interest in Bruce Power (the Arbitration). Both the action and the Arbitration relate to corrosion to a steam

generator unit discovered after OPG leased the Bruce nuclear generating stations to Bruce Power.

In 2012, the arbitrator found that British Energy was liable to the claimants for some of the damages they claimed.

The final settlement amount was valued by British Energy at $71 million. In September 2014, British Energy

amended its Statement of Claim (Amended Claim) to reduce the claim amount to $100 million to reflect that the

purchasers of British Energy’s interest in Bruce Power did not receive the full damages they originally claimed in the

Arbitration. British Energy also added an allegation to its Amended Claim that OPG breached a covenant to maintain

the steam generator between the time of the initial agreement to lease and the effective date of the lease in

accordance with “Good Utility Practices”.

Various other legal proceedings are pending against OPG or its subsidiaries covering a wide range of matters that

arise in the ordinary course of its business activities.

17

Each of these matters is subject to various uncertainties. Some of these matters may be resolved unfavourably.

While it is not possible to determine the ultimate outcome of the various pending actions, it is the Company’s belief

that their resolution is not likely to have a material adverse impact on its financial position.

Guarantees

The Company and its joint venture partners have jointly guaranteed the financial performance of jointly owned entities

related primarily to the payment of liabilities. As at March 31, 2016, the total amount of guarantees OPG provided to

these entities was $83 million. OPG may terminate some of these guarantees within a short time frame by providing

written notice to the counterparties at any time. Other guarantees have terms ending between 2019 and 2029. As at

March 31, 2016, the potential impact of the fair value of these guarantees to income has been estimated to be

negligible and OPG does not expect to make any payments associated with these guarantees.

Contractual and Commercial Commitments

OPG's contractual obligations as at March 31, 2016, are as follows:

(millions of dollars) 2016 1 2017 2018 2019 2020 Thereafter Total Fuel supply agreements 137 177 167 100 67 114 762 Contributions under the Ontario Nuclear 113 163 193 288 133 2,285 3,175 Funds Agreement 2 Contributions to the OPG registered 267 - - - - - 267 pension plan 3 Long-term debt repayment 273 1,103 398 368 663 2,667 5,472 Interest on long-term debt 178 242 186 167 145 2,275 3,193 Short-term debt repayment 249 - - - - - 249 Commitments related to Darlington 285 - - - - - 285 Refurbishment 4 Commitments related to Peter 135 33 - - - - 168 Sutherland Sr. GS Operating licence 31 43 37 23 24 142 300 Operating lease obligations 16 17 17 14 14 42 120 Unconditional purchase obligations 48 61 58 57 55 5 284 Accounts payable and accrued charges 890 5 11 - - 18 924 Other 54 14 5 2 2 69 146 Total 2,676 1,858 1,072 1,019 1,103 7,617 15,345 1 Represents amounts for the remainder of the year. 2 Contributions under the Ontario Nuclear Funds Agreement (ONFA) are based on the 2012 ONFA Reference Plan contribution

schedule approved in 2012. An updated ONFA Reference Plan is expected to be effective January 1, 2017. 3 The pension contributions include ongoing funding requirements and additional funding requirements towards the deficit, in

accordance with the actuarial valuation of the OPG registered pension plan as at January 1, 2014. The next actuarial valuation of the OPG registered pension plan must have an effective date no later than January 1, 2017. The pension contributions are affected by various factors including market performance, changes in actuarial assumptions, plan experience, changes in the pension regulatory environment, and the timing of funding valuations. Funding requirements after 2016 are excluded due to significant variability in the assumptions required to project the timing of future cash flows. The amount of OPG’s additional, voluntary contribution, if any, is revisited from time to time.

4 Estimated currently committed costs to close the project, including demobilization of project staff and cancellation of existing contracts and material orders.

18

12. BUSINESS SEGMENTS

  Segment Income Regulated Unregulated (Loss) for the Three Nuclear Services, Months Ended Waste Contracted Trading, March 31, 2016 Nuclear Manage- Hydro- Generation and other Non- (millions of dollars) Generation ment electric Portfolio Generation Elimination Total Revenue 926 34 385 145 21 (33) 1,478 Fuel expense 81 - 79 12 - - 172 Gross margin 845 34 306 133 21 (33) 1,306Operations, 563 36 76 40 4 (33) 686 maintenance and administration Depreciation and 230 - 56 19 7 - 312 amortization Accretion on fixed - 228 - 2 2 - 232 asset removal and nuclear waste management liabilities Earnings on nuclear - (147) - - - - (147) fixed asset removal and nuclear waste management funds Property taxes 7 - - 2 3 - 12 Income from - - - (8) - - (8) investments subject to significant influence Other gains (1) - (22) - - - (23) Income (loss) before interest and income taxes 46 (83) 196 78 5 - 242

 

19

Segment Income Regulated Unregulated (Loss) for the Three Months Ended Nuclear Services, March 31, 2015 Waste Contracted Trading, and (millions of dollars) Nuclear Manage- Hydro- Generation other Non- Generation ment electric Portfolio Generation Elimination Total Revenue 813 32 394 123 24 (31) 1,355 Fuel expense 78 - 71 7 1 - 157 Gross margin 735 32 323 116 23 (31) 1,198Operations, 526 34 76 44 16 (31) 665 maintenance and administration Depreciation and 114 - 60 17 5 - 196 amortization Accretion on fixed - 220 - 2 2 - 224 asset removal and nuclear waste management liabilities Earnings on nuclear - (231) - - - - (231) fixed asset removal and nuclear waste management funds Property taxes 7 - - 2 4 - 13 Income from - - - (11) - - (11) investments subject to significant influence Income (loss) before interest and income taxes 88 9 187 62 (4) - 342

13. NET CHANGES IN NON-CASH WORKING CAPITAL BALANCES

Three Months Ended March 31(millions of dollars) 2016 2015 Receivables from related parties (4) 56 Other accounts receivable and prepaid expenses (30) (20) Fuel inventory 11 10 Income taxes payable/recoverable 15 30 Materials and supplies 1 5 Accounts payable and accrued charges (115) (46) (122) 35

20

14. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE

Investments subject to significant influence consist of OPG’s 50 percent ownership interest in the jointly controlled

entities of the Portlands Energy Centre (PEC) gas-fired combined cycle generating station and the Brighton Beach

gas-fired combined cycle generating station (Brighton Beach), which are accounted for using the equity method.

Details of the balances as at March 31, 2016 and December 31, 2015 are as follows:

(millions of dollars) 2016 2015 PEC Current assets 15 14 Long-term assets 266 270 Current liabilities (7) (4) Long-term liabilities (5) (5) Brighton Beach Current assets 5 9 Long-term assets 174 177 Current liabilities (15) (15) Long-term debt (101) (104) Other long-term liabilities (6) (6) Investments subject to significant influence 326 336

15. SUBSEQUENT EVENT

During 2015, OPG entered into renewed three-year collective bargaining agreements with the Power Workers’ Union

(PWU) and The Society of Energy Professionals (The Society). Changes to the respective collective agreements

included increases to employee pension plan contributions and provisions for existing employees represented by the

PWU and The Society with eligibility to annually receive common shares of Hydro One Limited (Hydro One) for up to

15 years starting in the third year of the respective agreements.

In April 2016, OPG acquired nine million common shares of Hydro One at $23.65 per share as part of a secondary

share offering by the Province through a syndicate of underwriters. OPG paid the same price as other investors in

the offering. The acquisition was made for investment purposes to mitigate the risk of future price volatility related to

OPG’s future share delivery obligations under the collective agreements. The shares acquired in this transaction

represent the substantial majority of OPG’s currently anticipated purchases of Hydro One shares.